10-K 1 d78726e10vk.htm FORM 10-K e10vk
Table of Contents

 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
 
     
(Mark One)    
þ
  ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
    For the fiscal year ended December 31, 2010
or
o
  TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
Commission File Number 001-32318
Devon Energy Corporation
(Exact name of registrant as specified in its charter)
 
     
Delaware   73-1567067
(State of other jurisdiction of incorporation or organization)   (I.R.S. Employer identification No.)
20 North Broadway, Oklahoma City, Oklahoma   73102-8260
(Address of principal executive offices)   (Zip code)
 
Registrant’s telephone number, including area code:
(405) 235-3611
 
Securities registered pursuant to Section 12(b) of the Act:
 
     
Title of each class
 
Name of each exchange on which registered
 
Common stock, par value $0.10 per share
  The New York Stock Exchange
 
Securities registered pursuant to Section 12(g) of the Act:
None
 
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes þ     No o
 
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.  Yes o     No þ
 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes þ     No o
 
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes þ     No o
 
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  o
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
 
             
Large accelerated filer þ
  Accelerated filer o   Non-accelerated filer o   Smaller reporting company o
    (Do not check if a smaller reporting company)       
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  Yes o     No þ
 
The aggregate market value of the voting common stock held by non-affiliates of the registrant as of June 30, 2010, was approximately $26.6 billion, based upon the closing price of $60.92 per share as reported by the New York Stock Exchange on such date. On February 10, 2011, 427 million shares of common stock were outstanding.
 
DOCUMENTS INCORPORATED BY REFERENCE
Proxy statement for the 2011 annual meeting of stockholders — Part III
 


 

 
DEVON ENERGY CORPORATION
 
INDEX TO FORM 10-K ANNUAL REPORT
TO THE SECURITIES AND EXCHANGE COMMISSION
 
                 
        Definitions     3  
        Information Regarding Forward-Looking Statements     4  
       
      Business     5  
      Risk Factors     12  
      Unresolved Staff Comments     17  
      Properties     17  
      Legal Proceedings     30  
      Submission of Matters to a Vote of Security Holders     30  
       
      Market for Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities     31  
      Selected Financial Data     33  
      Management’s Discussion and Analysis of Financial Condition and Results of Operations     34  
      Quantitative and Qualitative Disclosures about Market Risk     71  
      Financial Statements and Supplementary Data     74  
      Changes in and Disagreements with Accountants on Accounting and Financial Disclosure     141  
      Controls and Procedures     141  
      Other Information     141  
       
      Directors, Executive Officers and Corporate Governance     142  
      Executive Compensation     142  
      Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters     142  
      Certain Relationships and Related Transactions, and Director Independence     142  
      Principal Accounting Fees and Services     142  
       
      Exhibits and Financial Statement Schedules     143  
    147  
 EX-10.15
 EX-10.16
 EX-10.18
 EX-10.21
 EX-10.22
 EX-12
 EX-21
 EX-23.1
 EX-23.2
 EX-23.3
 EX-31.1
 EX-31.2
 EX-32.1
 EX-32.2
 EX-99.1
 EX-99.2
 EX-101 INSTANCE DOCUMENT
 EX-101 SCHEMA DOCUMENT
 EX-101 CALCULATION LINKBASE DOCUMENT
 EX-101 LABELS LINKBASE DOCUMENT
 EX-101 PRESENTATION LINKBASE DOCUMENT
 EX-101 DEFINITION LINKBASE DOCUMENT


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DEFINITIONS
 
Measurements of Oil, Natural Gas and Natural Gas Liquids
 
  •  “NGL” or “NGLs” means natural gas liquids.
 
  •  “Oil” includes crude oil and condensate.
 
  •  “Bbl” means barrel of oil. One barrel equals 42 U.S. gallons.
 
  •  “MBbls” means thousand barrels.
 
  •  “MMBbls” means million barrels.
 
  •  “MBbls/d” means thousand barrels per day.
 
  •  “Mcf” means thousand cubic feet of natural gas.
 
  •  “MMcf” means million cubic feet.
 
  •  “Bcf” means billion cubic feet.
 
  •  “Bcfe” means billion cubic feet equivalent.
 
  •  “MMcf/d” means million cubic feet per day.
 
  •  “Boe” means barrel of oil equivalent, determined by using the ratio of one Bbl of oil or NGLs to six Mcf of gas.
 
  •  “MBoe” means thousand Boe.
 
  •  “MMBoe” means million Boe.
 
  •  “MBoe/d” means thousand Boe per day.
 
  •  “Btu” means British thermal units, a measure of heating value.
 
  •  “MMBtu” means million Btu.
 
  •  “MMBtu/d” means million Btu per day.
 
Geographic Areas
 
  •  “Canada” means the operations of Devon encompassing oil and gas properties located in Canada.
 
  •  “International” means the discontinued operations of Devon that encompass oil and gas properties that lie outside the United States and Canada.
 
  •  “North America Onshore” means the operations of Devon encompassing oil and gas properties in the continental United States and Canada.
 
  •  “U.S. Offshore” means the divested operations of Devon that encompassed oil and gas properties in the Gulf of Mexico.
 
  •  “U.S. Onshore” means the properties of Devon encompassing oil and gas properties in the continental United States.
 
Other
 
  •  “Federal Funds Rate” means the interest rate at which depository institutions lend balances at the Federal Reserve to other depository institutions overnight.
 
  •  “Inside FERC” refers to the publication Inside F.E.R.C.’s Gas Market Report.
 
  •  “LIBOR” means London Interbank Offered Rate.
 
  •  “NYMEX” means New York Mercantile Exchange.
 
  •  “SEC” means United States Securities and Exchange Commission.


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INFORMATION REGARDING FORWARD-LOOKING STATEMENTS
 
This report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements other than statements of historical facts included or incorporated by reference in this report, including, without limitation, statements regarding our future financial position, business strategy, budgets, projected revenues, projected costs and plans and objectives of management for future operations, are forward-looking statements. Such forward-looking statements are based on our examination of historical operating trends, the information used to prepare the December 31, 2010 reserve reports and other data in our possession or available from third parties. In addition, forward-looking statements generally can be identified by the use of forward-looking terminology such as “may,” “will,” “expect,” “intend,” “project,” “estimate,” “anticipate,” “believe,” or “continue” or similar terminology. Although we believe that the expectations reflected in such forward-looking statements are reasonable, we can give no assurance that such expectations will prove to have been correct. Important factors that could cause actual results to differ materially from our expectations include, but are not limited to, our assumptions about:
 
  •  energy markets, including the supply and demand for oil, gas, NGLs and other products or services, as well as the prices of oil, gas, NGLs and other products or services, including regional pricing differentials;
 
  •  production levels, including Canadian production subject to government royalties, which fluctuate with prices and production;
 
  •  reserve levels;
 
  •  competitive conditions;
 
  •  technology;
 
  •  the availability of capital resources within the securities or capital markets and related risks such as general credit, liquidity, market and interest-rate risks;
 
  •  capital expenditure and other contractual obligations;
 
  •  currency exchange rates;
 
  •  the weather;
 
  •  inflation;
 
  •  the availability of goods and services;
 
  •  drilling risks;
 
  •  future processing volumes and pipeline throughput;
 
  •  general economic conditions, whether internationally, nationally or in the jurisdictions in which we or our subsidiaries conduct business;
 
  •  public policy and government regulatory changes, including changes in royalty, production tax and income tax regimes, changes in hydraulic fracturing regulation, changes in environmental regulation and liability under federal, state, local or foreign environmental laws and regulations;
 
  •  terrorism;
 
  •  occurrence of property acquisitions or divestitures; and
 
  •  other factors disclosed under “Item 2. Properties” “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” and elsewhere in this report.
 
All subsequent written and oral forward-looking statements attributable to Devon, or persons acting on its behalf, are expressly qualified in their entirety by the cautionary statements. We assume no duty to update or revise our forward-looking statements based on changes in internal estimates or expectations or otherwise.


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PART I
 
Item 1.   Business
 
General
 
Devon Energy Corporation, including its subsidiaries (“Devon”), is an independent energy company engaged primarily in exploration, development and production of natural gas and oil. Our operations are concentrated in various North American onshore areas in the United States and Canada. We also have offshore operations located in Brazil and Angola that are currently in the process of being divested.
 
To complement our upstream oil and gas operations in North America, we have a large marketing and midstream operation. With these operations, we market gas, crude oil and NGLs. We also construct and operate pipelines, storage and treating facilities and natural gas processing plants. These midstream facilities are used to transport oil, gas, and NGLs and process natural gas.
 
We began operations in 1971 as a privately held company. We have been publicly held since 1988, and our common stock is listed on the New York Stock Exchange. Our principal and administrative offices are located at 20 North Broadway, Oklahoma City, OK 73102-8260 (telephone 405/235-3611).
 
Strategy
 
As an enterprise, we aspire to be the premier independent natural gas and oil company in North America. To achieve this, we continuously strive to optimize value for our shareholders by growing cash flows, earnings, production and reserves, all on a per debt-adjusted share basis. We do this by:
 
  •  exercising capital discipline;
 
  •  investing in oil and gas properties with high operating margins;
 
  •  balancing our reserves and production mix between natural gas and liquids;
 
  •  maintaining a low overall cost structure;
 
  •  improving performance through our marketing and midstream operations; and
 
  •  preserving financial flexibility.
 
Over the decade leading up to 2010, we captured an abundance of resources by carrying out this strategy. We pioneered horizontal drilling in the Barnett Shale and extended this technique to other natural gas shale plays in the United States and Canada. We became proficient with steam-assisted gravity drainage with our Jackfish oil sands development in Alberta, Canada. We achieved key oil discoveries with our drilling in the deepwater Gulf of Mexico and offshore Brazil. We have tripled our proved oil and gas reserves since 2000, and have also assembled an extensive inventory of exploration assets representing additional unproved resources.
 
Building off our past successes, in November 2009, we announced plans to strategically reposition Devon as a North American onshore exploration and production company. As part of this strategic repositioning, we are bringing forward the value of our offshore assets located in the Gulf of Mexico and countries outside North America by divesting them. As of the end of 2010, we had sold our properties in the Gulf of Mexico, Azerbaijan, China and other International regions, generating $5.6 billion in after-tax proceeds. Additionally, we have entered into agreements to sell our remaining offshore assets in Brazil and Angola and are waiting for the respective governments to approve the divestitures. Once the pending transactions are complete, we expect to have generated more than $8 billion in after-tax proceeds.
 
This repositioning has allowed us to focus our operations on our premier portfolio of North American onshore assets. Historically, our North American onshore assets have consistently provided us our highest risk-adjusted investment returns. By selling our offshore assets, we are able to conduct an aggressive, yet disciplined, pursuit of the untapped value of these North American onshore opportunities. More specifically,


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given the current challenged market for natural gas prices, our near-term focus is on the oil and liquids-rich opportunities that exist within our balanced portfolio of properties.
 
Besides investing in our onshore exploration and development opportunities, we are also using the divestiture proceeds to reduce our debt significantly and conduct up to a $3.5 billion common share repurchase program.
 
Presentation of Discontinued Operations
 
As a result of our November 2009 repositioning announcement, all amounts in this document related to our International operations are presented as discontinued. Therefore, financial data and operational data, such as reserves, production, wells and acreage, provided in this document exclude amounts related to our International operations unless otherwise provided.
 
Our U.S. Offshore operations do not qualify as discontinued operations under accounting rules. As such, financial and operational data provided in this document that pertain to our continuing operations include amounts related to our U.S. Offshore operations that were divested in 2010. Where appropriate, we have presented amounts related to our U.S. Offshore assets separate from those of our North American Onshore assets.
 
Development of Business
 
Since our first issuance of common stock to the public in 1988, we have executed strategies that have been focused on growth and value creation for our shareholders. We increased our total proved reserves from 8 MMBoe at year-end 1987 to 2,873 MMBoe at year-end 2010. During this same time period, we increased annual production from 1 MMBoe in 1987 to 228 MMBoe in 2010. Our expansion over this time period is attributable to a focused mergers and acquisitions program spanning a number of years, as well as active and successful exploration and development programs in more recent years. Additionally, our growth has provided meaningful value creation for our shareholders. The growth statistics from 1987 to 2010 translate into annual per share growth rates of 8% for production and 11% for reserves.
 
As a result of this growth, we have become one of the largest independent oil and gas companies in North America. During 2010, we continued to build off our past successes with a number of key accomplishments, including those discussed below.
 
  •  Drilling Success — We drilled 1,584 gross wells in 2010 on our North American onshore properties with a 99% success rate. We increased oil and NGL production from our North American onshore properties by 6% in 2010, to an average of 193 MBoe per day.
 
  •  Cana-Woodford Shale — We drilled 87 wells in the Cana-Woodford Shale play in western Oklahoma and more than doubled our industry-leading leasehold position in the play to more than 240,000 net acres. Our 2010 production exit rate from the Cana-Woodford increased more than 210% over the prior year to an average of 147 MMcf of gas equivalent per day, including 4 MBbls per day of liquids production. We also completed construction and commenced operation of our Cana gas processing plant in 2010.
 
  •  Permian Basin — We exited 2010 with Permian production of 45 MBoe per day, which represented a 16% increase compared to 2009. We have nearly one million net acres of leasehold in the region targeting various oil and liquids-rich play types.
 
  •  Jackfish — In 2010, our net production from our Jackfish oil sands project averaged 25 MBbls per day. Following scheduled facilities maintenance in the third quarter and a third-party pipeline system outage in the fourth quarter, our net Jackfish production ramped back up to 30 MBbls per day at year-end.
 
Construction of our second Jackfish project is now complete. We expect to begin injecting steam at Jackfish 2 in the second quarter, with first oil production expected by the end of 2011. We applied for regulatory approval of a third phase of Jackfish in the third quarter of 2010.


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  •  Pike — We added to our Canadian oil position by acquiring a 50% interest in the Pike oil sands leases. The Pike acreage lies immediately adjacent to our highly successful Jackfish project and has estimated gross recoverable resources that may exceed Jackfish. We are the operator of the project and are currently drilling appraisal wells and acquiring seismic data. The drilling results and seismic will help us determine the optimal configuration for the initial phase of development.
 
  •  Barnett Shale — Our 2010 production exit rate was 1.2 Bcfe per day, including 43 MBbls per day of liquids production. This represents a 16% increase in total production compared to the 2009 exit rate.
 
Financial Information about Segments and Geographical Areas
 
Notes 20 and 22 to the consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data” of this report contain information on our segments and geographical areas.
 
Oil, Natural Gas and NGL Marketing and Delivery Commitments
 
The spot markets for oil, gas and NGLs are subject to volatility as supply and demand factors fluctuate. As detailed below, we sell our production under both long-term (one year or more) or short-term (less than one year) agreements. Regardless of the term of the contract, the vast majority of our production is sold at variable or market sensitive prices.
 
Additionally, we may periodically enter into financial hedging arrangements or fixed-price contracts associated with a portion of our oil and gas production. These activities are intended to support targeted price levels and to manage our exposure to price fluctuations. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk.”
 
Oil Marketing
 
Our oil production is sold under both long-term and short-term agreements at prices negotiated with third parties. Although exact percentages vary daily, as of January 2011, approximately 81% of our oil production was sold under short-term contracts at variable or market-sensitive prices. The remaining 19% of oil production was sold under long-term, market-indexed contracts that are subject to market pricing variations.
 
Natural Gas Marketing
 
Our gas production is also sold under both long-term and short-term agreements at prices negotiated with third parties. Although exact percentages vary daily, as of January 2011, approximately 81% of our gas production was sold under short-term contracts at variable or market-sensitive prices. These market-sensitive sales are referred to as “spot market” sales. Another 18% of our production was committed under various long-term contracts, which dedicate the gas to a purchaser for an extended period of time, but still at market-sensitive prices. The remaining 1% of our gas production was sold under long-term, fixed-price contracts.
 
NGL Marketing
 
Our NGL production is sold under both long-term and short-term agreements at prices negotiated with third parties. Although exact percentages vary, as of January 2011, approximately 83% of our NGL production was sold under short-term contracts at variable or market-sensitive prices. Approximately 9% of our NGL production was sold under short-term, fixed-price contracts. The remaining 8% of NGL production was sold under long-term, market-sensitive price contracts.


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Delivery Commitments
 
A portion of our production is sold under certain contractual arrangements that specify the delivery of a fixed and determinable quantity. Although exact amounts vary, as of January 2011, we were committed to deliver the following fixed quantities of our oil and natural gas production:
 
                                         
          Less Than
    1-3
    3-5
    More Than
 
    Total     1 Year     Years     Years     5 Years  
 
Oil (MMBbls)
    210       14       41       43       112  
Natural gas (Bcf)
    607       226       223       103       55  
NGLs (MMBbls)
    13       13                    
                                         
Total (MMBoe)(1)
    324       65       78       60       121  
                                         
 
 
(1) Gas volumes are converted to Boe at the rate of six Mcf of gas per Bbl of oil, based upon the approximate relative energy content of gas and oil. NGLs are converted to Boe on a one-to-one basis with oil.
 
We expect to fulfill our delivery commitments over the next three years with production from our proved developed reserves. We expect to fulfill our longer-term delivery commitments beyond three years primarily with our proved developed reserves. In certain regions, we expect to fulfill these longer-term delivery commitments with our proved undeveloped reserves. See Note 22 to the consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data” of this report for information related to our proved reserves, including the development of our proved undeveloped reserves.
 
Our proved reserves have been sufficient to satisfy our delivery commitments during the three most recent years, and we expect such reserves will continue to satisfy our future delivery commitments. However, should our proved reserves not be sufficient to satisfy our future delivery commitments, we can and may use spot market purchases to fulfill the commitments.
 
Marketing and Midstream Activities
 
The primary objective of our marketing and midstream operations is to add value to us and other producers to whom we provide such services by gathering, processing and marketing oil, gas and NGL production in a timely and efficient manner. Our most significant midstream asset is the Bridgeport processing plant and gathering system located in north Texas. These facilities serve not only our gas production from the Barnett Shale but also gas production of other producers in the area. We have other natural gas processing plants that support our operations, including a plant completed in 2010 that serves the Cana-Woodford Shale production. Our midstream assets also include our 50% interest in the Access Pipeline transportation system in Canada. This pipeline system allows us to blend our Jackfish heavy oil production with condensate or other blend-stock and transport the combined product to the Edmonton area for sale.
 
Our marketing and midstream revenues are primarily generated by:
 
  •  selling NGLs that are either extracted from the gas streams processed by our plants or purchased from third parties for marketing, and
 
  •  selling or gathering gas that moves through our transport pipelines and unrelated third-party pipelines.
 
Our marketing and midstream costs and expenses are primarily incurred from:
 
  •  purchasing the gas streams entering our transport pipelines and plants;
 
  •  purchasing fuel needed to operate our plants, compressors and related pipeline facilities;
 
  •  purchasing third-party NGLs;
 
  •  operating our plants, gathering systems and related facilities; and
 
  •  transporting products on unrelated third-party pipelines.


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Customers
 
We sell our gas production to a variety of customers including pipelines, utilities, gas marketing firms, industrial users and local distribution companies. Gathering systems and interstate and intrastate pipelines are used to consummate gas sales and deliveries.
 
The principal customers for our crude oil production are refiners, remarketers and other companies, some of which have pipeline facilities near the producing properties. In the event pipeline facilities are not conveniently available, crude oil is trucked or shipped to storage, refining or pipeline facilities.
 
Our NGL production is primarily sold to customers engaged in petrochemical, refining and heavy oil blending activities. Pipelines, railcars and trucks are utilized to move our products to market.
 
During 2010, 2009 and 2008, no purchaser accounted for over 10% of our revenues.
 
Seasonal Nature of Business
 
Generally, the demand for natural gas decreases during the summer months and increases during the winter months. Seasonal anomalies such as mild winters or hot summers sometimes lessen this fluctuation. In addition, pipelines, utilities, local distribution companies and industrial users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer. This can also lessen seasonal demand fluctuations.
 
Public Policy and Government Regulation
 
The oil and natural gas industry is subject to various types of regulation throughout the world. Laws, rules, regulations and other policy implementations affecting the oil and natural gas industry have been pervasive and are under constant review for amendment or expansion. Pursuant to public policy changes, numerous government agencies have issued extensive laws and regulations binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Such laws and regulations have a significant impact on oil and gas exploration, production and marketing and midstream activities. These laws and regulations increase the cost of doing business and, consequently, affect profitability. Because public policy changes affecting the oil and natural gas industry are commonplace and because existing laws and regulations are frequently amended or reinterpreted, we are unable to predict the future cost or impact of complying with such laws and regulations. However, we do not expect that any of these laws and regulations will affect our operations in a manner materially different than they would affect other oil and natural gas companies of similar size and financial strength.
 
During 2010, as part of a strategic restructuring of the company, we sold our properties in the Gulf of Mexico and the majority of our assets outside North America, Additionally, we have entered into agreements to sell our remaining offshore assets in Brazil and Angola and are waiting for the respective governments to approve the divestitures. These divestitures reduce our vulnerability to laws, rules and regulations imposed by foreign governments, as well as those imposed in the United States for offshore exploration and production. The following are significant areas of government control and regulation affecting our operations in the United States and Canada.
 
Exploration and Production Regulation
 
Our oil and gas operations are subject to various federal, state, provincial, tribal and local laws and regulations. These laws and regulations relate to matters that include, but are not limited to:
 
  •  acquisition of seismic data;
 
  •  location of wells;
 
  •  drilling and casing of wells;
 
  •  hydraulic fracturing;


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  •  well production;
 
  •  spill prevention plans;
 
  •  emissions and discharge permitting;
 
  •  use, transportation, storage and disposal of fluids and materials incidental to oil and gas operations;
 
  •  surface usage and the restoration of properties upon which wells have been drilled;
 
  •  calculation and disbursement of royalty payments and production taxes;
 
  •  plugging and abandoning of wells; and
 
  •  transportation of production.
 
Our operations also are subject to conservation regulations, including the regulation of the size of drilling and spacing units or proration units; the number of wells that may be drilled in a unit; the rate of production allowable from oil and gas wells; and the unitization or pooling of oil and gas properties. In the United States, some states allow the forced pooling or integration of tracts to facilitate exploration, while other states rely on voluntary pooling of lands and leases, which may make it more difficult to develop oil and gas properties. In addition, state conservation laws generally limit the venting or flaring of natural gas and impose certain requirements regarding the ratable purchase of production. The effect of these regulations is to limit the amounts of oil and gas we can produce from our wells and to limit the number of wells or the locations at which we can drill.
 
Certain of our U.S. natural gas and oil leases are granted by the federal government and administered by the Bureau of Land Management of the Department of the Interior. Such leases require compliance with detailed federal regulations and orders that regulate, among other matters, drilling and operations on lands covered by these leases, and calculation and disbursement of royalty payments to the federal government. The federal government has been particularly active in recent years in evaluating and, in some cases, promulgating new rules and regulations regarding competitive lease bidding and royalty payment obligations for production from federal lands.
 
Royalties and Incentives in Canada
 
The royalty system in Canada is a significant factor in the profitability of oil and gas production. Royalties payable on production from lands other than Crown lands are determined by negotiations between the parties. Crown royalties are determined by government regulation and are generally calculated as a percentage of the value of the gross production, with the royalty rate dependent in part upon prescribed reference prices, well productivity, geographical location and the type and quality of the petroleum product produced. From time to time, the federal and provincial governments of Canada also have established incentive programs such as royalty rate reductions, royalty holidays, tax credits and fixed rate and profit-sharing royalties for the purpose of encouraging oil and gas exploration or enhanced recovery projects. These incentives generally have the effect of increasing our revenues, earnings and cash flow.
 
Pricing and Marketing in Canada
 
Any oil or gas export to be made pursuant to an export contract that exceeds a certain duration or a certain quantity requires an exporter to obtain export authorizations from Canada’s National Energy Board (“NEB”). The governments of Alberta, British Columbia and Saskatchewan also regulate the volume of natural gas that may be removed from those provinces for consumption elsewhere.


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Environmental and Occupational Regulations
 
We are subject to various federal, state, provincial, tribal and local international laws and regulations concerning occupational safety and health as well as the discharge of materials into, and the protection of, the environment. Environmental laws and regulations relate to, among other things:
 
  •  assessing the environmental impact of seismic acquisition, drilling or construction activities;
 
  •  the generation, storage, transportation and disposal of waste materials;
 
  •  the emission of certain gases into the atmosphere;
 
  •  the monitoring, abandonment, reclamation and remediation of well and other sites, including sites of former operations; and
 
  •  the development of emergency response and spill contingency plans.
 
The application of worldwide standards, such as ISO 14000 governing environmental management systems, is required to be implemented for some international oil and gas operations.
 
We consider the costs of environmental protection and safety and health compliance necessary and manageable parts of our business. We have been able to plan for and comply with environmental, safety and health initiatives without materially altering our operating strategy or incurring significant unreimbursed expenditures. However, based on regulatory trends and increasingly stringent laws, our capital expenditures and operating expenses related to the protection of the environment and safety and health compliance have increased over the years and will likely continue to increase. We cannot predict with any reasonable degree of certainty our future exposure concerning such matters.
 
We maintain levels of insurance customary in the industry to limit our financial exposure in the event of a substantial environmental claim resulting from sudden, unanticipated and accidental discharges of oil, salt water or other substances. However, we do not maintain 100% coverage concerning any environmental claim, and no coverage is maintained with respect to any penalty or fine required to be paid because of a violation of law.
 
In 2010, the United States Environmental Protection Agency (“EPA”) issued rules requiring oil and natural gas companies to track and report their greenhouse gas emissions. For Devon, this involves collecting emissions data at more than 17,000 well sites and numerous natural gas plants and compressor stations. While these rules increase our cost of doing business, we do not anticipate that we would be impacted to any greater degree than other similar oil and natural gas companies.
 
The Kyoto Protocol was adopted by numerous countries in 1997 and implemented in 2005. The Protocol requires reductions of certain emissions of greenhouse gases. Although the United States has not ratified the Protocol, the other countries in which we operate have. In 2007, Canada ratified the Kyoto Protocol and committed to reducing Canada’s greenhouse gas emissions. This commitment was renewed by signing the Copenhagen Accord in 2009 and the Cancun Agreement in 2010. Although there is no framework in place, Canada remains focused on the original reduction target of the Kyoto Protocol and is working to align greenhouse gas policy with the United States. The mandatory reductions on greenhouse gas emissions will create additional costs for the Canadian oil and gas industry, including Devon. Provincially, British Columbia and Alberta have greenhouse gas legislation and regulation that carry some compliance burden for the oil and gas sector. Presently, it is not possible to accurately estimate the costs we could incur to comply with any future laws or regulations developed to achieve emissions reductions in Canada or elsewhere, but such expenditures could be substantial.
 
In 2006, we established our Corporate Climate Change Position and Strategy. Key components of the strategy include initiation of energy efficiency measures, tracking emerging climate change legislation and publication of a corporate greenhouse gas emission inventory. We last published our emission inventory on January 2008. We will publish another emission inventory on or before March 31, 2011 to comply with a reporting mandate issued by the EPA. Additionally, we continue to explore energy efficiency measures and


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greenhouse emission reduction opportunities. We also continue to monitor legislative and regulatory climate change developments, such as the proposals described above.
 
Employees
 
As of December 31, 2010, we had approximately 5,000 employees. We consider labor relations with our employees to be satisfactory. We have not had any work stoppages or strikes pertaining to our employees.
 
Competition
 
See “Item 1A. Risk Factors.”
 
Availability of Reports
 
Through our website, http://www.devonenergy.com, we make available electronic copies of the charters of the committees of our Board of Directors, other documents related to our corporate governance (including our Code of Ethics for the Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer), and documents we file or furnish to the SEC, including our annual reports on Form 10-K, quarterly reports on Form 10-Q, and current reports on Form 8-K, as well as any amendments to these reports. Access to these electronic filings is available free of charge as soon as reasonably practicable after filing or furnishing them to the SEC. Printed copies of our committee charters or other governance documents and filings can be requested by writing to our corporate secretary at the address on the cover of this report.
 
Item 1A.   Risk Factors
 
Our business activities, and the oil and gas industry in general, are subject to a variety of risks. If any of the following risk factors should occur, our profitability, financial condition or liquidity could be materially impacted. As a result, holders of our securities could lose part or all of their investment in Devon.
 
Oil, Gas and NGL Prices are Volatile
 
Our financial results are highly dependent on the general supply and demand for oil, gas and NGLs, which impact the prices we ultimately realize on our sales of these commodities. A significant downward movement of the prices for these commodities could have a material adverse effect on our revenues, operating cash flows and profitability. Such a downward price movement could also have a material adverse effect on our estimated proved reserves, the carrying value of our oil and gas properties, the level of planned drilling activities and future growth. Historically, market prices and our realized prices have been volatile and are likely to continue to be volatile in the future due to numerous factors beyond our control. These factors include, but are not limited to:
 
  •  consumer demand for oil, gas and NGLs;
 
  •  conservation efforts;
 
  •  OPEC production levels;
 
  •  weather;
 
  •  regional pricing differentials;
 
  •  differing quality of oil produced (i.e., sweet crude versus heavy or sour crude);
 
  •  differing quality and NGL content of gas produced;
 
  •  the level of imports and exports of oil, gas and NGLs;
 
  •  the price and availability of alternative fuels;
 
  •  the overall economic environment; and
 
  •  governmental regulations and taxes.


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Estimates of Oil, Gas and NGL Reserves are Uncertain
 
The process of estimating oil, gas and NGL reserves is complex and requires significant judgment in the evaluation of available geological, engineering and economic data for each reservoir, particularly for new discoveries. Because of the high degree of judgment involved, different reserve engineers may develop different estimates of reserve quantities and related revenue based on the same data. In addition, the reserve estimates for a given reservoir may change substantially over time as a result of several factors including additional development activity, the viability of production under varying economic conditions and variations in production levels and associated costs. Consequently, material revisions to existing reserve estimates may occur as a result of changes in any of these factors. Such revisions to proved reserves could have a material adverse effect on our estimates of future net revenue, as well as our financial condition and profitability. Additional discussion of our policies and internal controls related to estimating and recording reserves is described in “Item 2. Properties — Preparation of Reserves Estimates and Reserves Audits.”
 
Discoveries or Acquisitions of Additional Reserves are Needed to Avoid a Material Decline in Reserves and Production
 
The production rates from oil and gas properties generally decline as reserves are depleted, while related per unit production costs generally increase, due to decreasing reservoir pressures and other factors. Therefore, our estimated proved reserves and future oil, gas and NGL production will decline materially as reserves are produced unless we conduct successful exploration and development activities or, through engineering studies, identify additional producing zones in existing wells, secondary or tertiary recovery techniques, or acquire additional properties containing proved reserves. Consequently, our future oil, gas and NGL production and related per unit production costs are highly dependent upon our level of success in finding or acquiring additional reserves.
 
Future Exploration and Drilling Results are Uncertain and Involve Substantial Costs
 
Substantial costs are often required to locate and acquire properties and drill exploratory wells. Such activities are subject to numerous risks, including the risk that we will not encounter commercially productive oil or gas reservoirs. The costs of drilling and completing wells are often uncertain. In addition, oil and gas properties can become damaged or drilling operations may be curtailed, delayed or canceled as a result of a variety of factors including, but not limited to:
 
  •  unexpected drilling conditions;
 
  •  pressure or irregularities in reservoir formations;
 
  •  equipment failures or accidents;
 
  •  fires, explosions, blowouts and surface cratering;
 
  •  adverse weather conditions;
 
  •  lack of access to pipelines or other transportation methods;
 
  •  environmental hazards or liabilities; and
 
  •  shortages or delays in the availability of services or delivery of equipment.
 
A significant occurrence of one of these factors could result in a partial or total loss of our investment in a particular property. In addition, drilling activities may not be successful in establishing proved reserves. Such a failure could have an adverse effect on our future results of operations and financial condition. While both exploratory and developmental drilling activities involve these risks, exploratory drilling involves greater risks of dry holes or failure to find commercial quantities of hydrocarbons.


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Industry Competition For Leases, Materials, People and Capital Can Be Significant
 
Strong competition exists in all sectors of the oil and gas industry. We compete with major integrated and other independent oil and gas companies for the acquisition of oil and gas leases and properties. We also compete for the equipment and personnel required to explore, develop and operate properties. Competition is also prevalent in the marketing of oil, gas and NGLs. Typically, during times of high or rising commodity prices, drilling and operating costs will also increase. Higher prices will also generally increase the costs of properties available for acquisition. Certain of our competitors have financial and other resources substantially larger than ours. They also may have established strategic long-term positions and relationships in areas in which we may seek new entry. As a consequence, we may be at a competitive disadvantage in bidding for drilling rights. In addition, many of our larger competitors may have a competitive advantage when responding to factors that affect demand for oil and gas production, such as changing worldwide price and production levels, the cost and availability of alternative fuels, and the application of government regulations.
 
Midstream Capacity Constraints and Interruptions Impact Commodity Sales
 
We rely on midstream facilities and systems to process our natural gas production and to transport our production to downstream markets. Such midstream systems include the systems we operate, as well as systems operated by a number of different third parties. When possible, we gain access to midstream systems that provide the most advantageous downstream market prices available to us.
 
Regardless of who operates the midstream systems we rely upon, a portion of our production in any region may be interrupted or shut in from time to time due to loss of access to plants, pipelines or gathering systems. Such access could be lost due to a number of factors, including, but not limited to, weather conditions, accidents, field labor issues or strikes. Additionally, we and third-parties may be subject to constraints that limit our ability to construct, maintain or repair midstream facilities needed to process and transport our production. Such interruptions or constraints could negatively impact our production and associated profitability.
 
Hedging Activities Limit Participation in Commodity Price Increases and Increase Exposure to Counterparty Credit Risk
 
We periodically enter into hedging activities with respect to a portion of our production to manage our exposure to oil, gas and NGL price volatility. To the extent that we engage in price risk management activities to protect ourselves from commodity price declines, we may be prevented from fully realizing the benefits of commodity price increases above the prices established by our hedging contracts. In addition, our hedging arrangements may expose us to the risk of financial loss in certain circumstances, including instances in which the counterparties to our hedging contracts fail to perform under the contracts.
 
Public Policy, Which Includes Laws, Rules and Regulations, Can Change
 
Our operations are generally subject to federal laws, rules and regulations in the United States and Canada. In addition, we are also subject to the laws and regulations of various states, provinces, tribal and local governments. Pursuant to public policy changes, numerous government departments and agencies have issued extensive rules and regulations binding on the oil and gas industry and its individual members, some of which carry substantial penalties for failure to comply. Changes in such public policy have affected, and at times in the future could affect, our operations. Political developments can restrict production levels, enact price controls, change environmental protection requirements, and increase taxes, royalties and other amounts payable to governments or governmental agencies. Existing laws and regulations can also require us to incur substantial costs to maintain regulatory compliance. Our operating and other compliance costs could increase further if existing laws and regulations are revised or reinterpreted or if new laws and regulations become applicable to our operations. Although we are unable to predict changes to existing laws and regulations, such changes could significantly impact our profitability, financial condition and liquidity, particularly changes related to hydraulic fracturing, income taxes and climate change as discussed below.


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Hydraulic Fracturing — The U.S. Congress is currently considering legislation to amend the federal Safe Drinking Water Act to require the disclosure of chemicals used by the oil and natural-gas industry in the hydraulic-fracturing process. Currently, regulation of hydraulic fracturing is primarily conducted at the state level through permitting and other compliance requirements. This legislation, if adopted, could establish an additional level of regulation and permitting at the federal level.
 
Income Taxes — The U.S. President’s recent budget proposals include provisions that would, if enacted, make significant changes to United States tax laws. The most significant change would eliminate the immediate deduction for intangible drilling and development costs.
 
Climate Change — Policy makers in the United States are increasingly focusing on whether the emissions of greenhouse gases, such as carbon dioxide and methane, are contributing to harmful climatic changes. Policy makers at both the United States federal and state level have introduced legislation and proposed new regulations that are designed to quantify and limit the emission of greenhouse gases through inventories and limitations on greenhouse gas emissions. Legislative initiatives to date have focused on the development of cap-and-trade programs. These programs generally would cap overall greenhouse gas emissions on an economy-wide basis and require major sources of greenhouse gas emissions or major fuel producers to acquire and surrender emission allowances. Cap-and-trade programs would be relevant to our operations because the equipment we use to explore for, develop, produce and process oil and natural gas emits greenhouse gases. Additionally, the combustion of carbon-based fuels, such as the oil, gas and NGLs we sell, emits carbon dioxide and other greenhouse gases.
 
Environmental Matters and Costs Can Be Significant
 
As an owner, lessee or operator of oil and gas properties, we are subject to various federal, state, provincial, tribal and local laws and regulations relating to discharge of materials into, and protection of, the environment. These laws and regulations may, among other things, impose liability on us for the cost of pollution clean-up resulting from our operations in affected areas. Any future environmental costs of fulfilling our commitments to the environment are uncertain and will be governed by several factors, including future changes to regulatory requirements. There is no assurance that changes in or additions to public policy regarding the protection of the environment will not have a significant impact on our operations and profitability.
 
Insurance Does Not Cover All Risks
 
Exploration, development, production and processing of oil, gas and NGLs can be hazardous and involve unforeseen occurrence including, but not limited to blowouts, cratering, fires and loss of well control. These occurrences can result in damage to or destruction of wells or production facilities, injury to persons, loss of life, or damage to property or the environment. We maintain insurance against certain losses or liabilities in accordance with customary industry practices and in amounts that management believes to be prudent. However, insurance against all operational risks is not available to us.
 
International Operations Have Uncertain Political, Economic and Other Risks
 
Our operations outside North America are based in Brazil and Angola. As noted earlier in this report, we are in the process of divesting our operations outside North America. However, until we cease operating in these locations, we face political and economic risks and other uncertainties in these areas that are more prevalent than what exist for our operations in North America. Such factors include, but are not limited to:
 
  •  general strikes and civil unrest;
 
  •  the risk of war, acts of terrorism, expropriation, forced renegotiation or modification of existing contracts;
 
  •  import and export regulations;


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  •  taxation policies, including royalty and tax increases and retroactive tax claims, and investment restrictions;
 
  •  transportation regulations and tariffs;
 
  •  exchange controls, currency fluctuations, devaluation or other activities that limit or disrupt markets and restrict payments or the movement of funds;
 
  •  laws and policies of the United States affecting foreign trade, including trade sanctions;
 
  •  the possibility of being subject to exclusive jurisdiction of foreign courts in connection with legal disputes relating to licenses to operate and concession rights in countries where we currently operate;
 
  •  the possible inability to subject foreign persons to the jurisdiction of courts in the United States; and
 
  •  difficulties enforcing our rights against a governmental agency because of the doctrine of sovereign immunity and foreign sovereignty over international operations.
 
Foreign countries have occasionally asserted rights to oil and gas properties through border disputes. If a country claims superior rights to oil and gas leases or concessions granted to us by another country, our interests could decrease in value or be lost. These assets may affect our overall business and results of operations by distracting management’s attention from our more significant assets. Various regions of the world have a history of political and economic instability. This instability could result in new governments or the adoption of new policies that might result in a substantially more hostile attitude toward foreign investment. In an extreme case, such a change could result in termination of contract rights and expropriation of foreign-owned assets. This could adversely affect our interests and our future profitability.
 
The impact that future terrorist attacks or regional hostilities may have on the oil and gas industry in general, and on our operations in particular, is not known at this time. Uncertainty surrounding military strikes or a sustained military campaign may affect our operations in unpredictable ways, including disruptions of fuel supplies and markets, particularly oil, and the possibility that infrastructure facilities, including pipelines, production facilities, processing plants and refineries, could be direct targets of, or indirect casualties of, an act of terror or war. We may be required to incur significant costs in the future to safeguard our assets against terrorist activities.
 
Certain of Our Investments Are Subject To Risks That May Affect Their Liquidity and Value
 
To maximize earnings on available cash balances, we periodically invest in securities that we consider to be short-term in nature and generally available for short-term liquidity needs. During 2007, we purchased asset-backed securities that have an auction rate reset feature (“auction rate securities”). Our auction rate securities generally have contractual maturities of more than 20 years. However, the underlying interest rates on our securities are scheduled to reset every seven to 28 days. Therefore, when we bought these securities, they were generally priced and subsequently traded as short-term investments because of the interest rate reset feature. At December 31, 2010, our auction rate securities totaled $94 million.
 
Since February 8, 2008, we have experienced difficulty selling our securities due to the failure of the auction mechanism, which provided liquidity to these securities. An auction failure means that the parties wishing to sell securities could not do so. The securities for which auctions have failed will continue to accrue interest and be auctioned every seven to 28 days until the auction succeeds, the issuer calls the securities or the securities mature. Due to continued auction failures throughout 2009 and 2010, we consider these investments to be long-term in nature and generally not available for short-term liquidity needs. Therefore, we have classified these investments as other long-term assets.
 
Our auction rate securities are rated AAA — the highest rating — by one or more rating agencies and are collateralized by student loans that are substantially guaranteed by the United States government. These investments are subject to general credit, liquidity, market and interest rate risks, which may be exacerbated by problems in the global credit markets, including but not limited to, U.S. subprime mortgage defaults and writedowns by major financial institutions due to deteriorating values of their asset portfolios. These and other


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related factors have affected various sectors of the financial markets and caused credit and liquidity issues. If issuers are unable to successfully close future auctions and their credit ratings deteriorate, our ability to liquidate these securities and fully recover the carrying value of our investment in the near term may be limited. Under such circumstances, we may record an impairment charge on these investments in the future.
 
Item 1B.   Unresolved Staff Comments
 
Not applicable.
 
Item 2.   Properties
 
Property Overview
 
Our oil and gas operations are concentrated within various North American onshore basins across the United States and Canada. Our properties consist of interests in developed and undeveloped oil and gas leases and mineral acreage in these regions. These ownership interests entitle us to drill for and produce oil, natural gas and NGLs from specific areas. Our interests are mostly in the form of working interests and, to a lesser extent, overriding royalty, mineral, and other forms of direct and indirect ownership in oil and gas properties.
 
As previously mentioned, we have completed substantially all of our offshore divestitures, with the exception of assets in Brazil and Angola. We have entered into agreements to sell these assets and are waiting for the respective governments to approve the divestitures.
 
We also have a substantial midstream business that includes natural gas and NGL processing plants and pipeline systems across North America. In aggregate, we have ownership in approximately 13,000 miles of pipeline and 65 natural gas processing and treating plants. Our most significant concentration of midstream assets is located in north Texas at our Barnett Shale field. These assets include over 3,000 miles of pipeline, two natural gas processing plants with 750 MMcf per day of total capacity, and a 15 MBbls per day NGL fractionator. In 2010, we completed construction of a natural gas processing plant to support the growing development of our Cana-Woodford Shale properties. The Cana plant has an initial capacity of 200 MMcf per day with the design capacity to expand up to 600 MMcf per day.
 
Our midstream assets also include the Access Pipeline transportation system in Canada. This 220-mile dual pipeline system extends from our Jackfish operations in Alberta with connectivity to a 350 MBbls storage terminal near Edmonton. The dual pipeline system allows us to deliver diluents to Jackfish for the blending of our heavy oil production and transport the combined product to the Edmonton crude oil market for sale. We have a 50% ownership interest in the Access Pipeline.


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The following sections provide additional details of our oil and gas properties, including information about proved reserves, production, wells, acreage and drilling activities.
 
Property Profiles
 
The locations of our key properties are presented on the following map.
 


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The following table presents proved reserve information for our key properties as of December 31, 2010, along with their production volumes for the year 2010. Our key properties include those that currently have significant proved reserves or production. These key properties also include properties that do not have current significant levels of proved reserves or production, but are expected be the source of future significant growth in proved reserves and production.
 
                                 
    Proved
    Proved
             
    Reserves
    Reserves
    Production
    Production
 
    (MMBoe)(1)     %(2)     (MMBoe)(1)     %(2)  
 
U.S.
                               
Barnett Shale
    1,112       38.7 %     70       31.6 %
Carthage
    182       6.3 %     12       5.6 %
Cana-Woodford Shale
    175       6.1 %     7       3.0 %
Permian Basin
    167       5.8 %     16       7.0 %
Washakie
    95       3.3 %     8       3.7 %
Arkoma-Woodford Shale
    48       1.7 %     5       2.1 %
Groesbeck
    48       1.7 %     6       2.6 %
Granite Wash
    40       1.4 %     4       1.8 %
Haynesville-Bossier Shale
    11       0.4 %     1       0.6 %
Other U.S. Onshore
    229       7.9 %     29       13.1 %
                                 
Total U.S. Onshore
    2,107       73.3 %     158       71.1 %
                                 
Canada
                               
Jackfish
    440       15.3 %     9       4.1 %
Northwest
    107       3.7 %     15       6.6 %
Lloydminster
    65       2.3 %     15       6.7 %
Deep Basin
    56       2.0 %     10       4.5 %
Horn River Basin
    11       0.4 %     1       0.2 %
Pike
                       
Other Canada
    87       3.0 %     15       6.8 %
                                 
Total Canada
    766       26.7 %     65       28.9 %
                                 
North America Onshore
    2,873       100.0 %     223       100.0 %
                                 
 
 
(1) Gas reserves and production are converted to Boe at the rate of six Mcf of gas per Bbl of oil, based upon the approximate relative energy content of gas and oil, which rate is not necessarily indicative of the relationship of gas and oil prices. NGL reserves and production are converted to Boe on a one-to-one basis with oil.
 
(2) Percentage of proved reserves and production the property bears to total proved reserves and production based on actual figures and not the rounded figures included in this table.
 
The following profile information includes the location, acreage, formation type, average working interest and 2010 drilling activities of our key properties presented in the table above. Due to the continued depressed natural gas price environment, we are shifting the vast majority of our 2011 drilling activity to focus on the oil and liquids-rich gas properties within our portfolio. For the key properties that are primarily liquids-based, we also provide our 2011 drilling plans in the profile information below.
 
U.S.
 
Barnett Shale — The Barnett Shale, located in north Texas, is our largest property both in terms of production and proved reserves. Our leases include approximately 630,000 net acres located primarily in Denton, Johnson, Parker, Tarrant and Wise counties. The Barnett Shale is a non-conventional reservoir and it


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produces natural gas and NGLs. We have an average working interest of 89%. We drilled 460 gross wells in 2010 and plan to drill approximately 320 gross wells in 2011.
 
Carthage — The Carthage area in east Texas includes primarily Harrison, Marion, Panola and Shelby counties. Our average working interest is 86% and we hold approximately 225,000 net acres. Our Carthage area wells produce primarily natural gas and NGLs from conventional reservoirs. We drilled 26 gross wells in 2010 in this area.
 
Cana-Woodford Shale — The Cana-Woodford Shale is located primarily in Canadian, Blaine, Caddo, and Dewey counties in western Oklahoma. Our average working interest is 52% and we hold more than 240,000 net acres. Our Cana-Woodford Shale properties produce natural gas, NGLs and condensate from a non-conventional reservoir. We drilled 87 gross wells in 2010 and plan to drill around 220 gross wells in 2011.
 
Permian Basin — Our oil and gas properties in the Permian Basin in west Texas and southeast New Mexico comprise approximately 950,000 net acres. Our drilling activity is targeting the liquids-rich targets within the Avalon Shale, Bone Spring, Wolfberry and undisclosed play types within other conventional reservoirs. Our average working interest in these properties is 53%. In 2010, we drilled 262 gross wells and plan to drill approximately 300 gross wells in 2011.
 
Washakie — Our Washakie area leases are concentrated in Carbon and Sweetwater counties in southern Wyoming. Our average working interest is about 76% and we hold about 160,000 net acres in the area. The Washakie wells produce primarily natural gas from conventional reservoirs. In 2010, we drilled 93 gross wells.
 
Arkoma-Woodford Shale — Our Arkoma-Woodford Shale properties in southeastern Oklahoma produce natural gas and NGLs from a non-conventional reservoir. Our more than 55,000 net acres are concentrated in Coal and Hughes counties, and we have an average working interest of about 31%. In 2010, we drilled 61 gross wells in this area.
 
Groesbeck — The Groesbeck area of east Texas includes portions of Freestone, Leon, Limestone and Robertson counties. Our average working interest is 72% and we hold about 130,000 net acres of land. The Groesbeck wells produce primarily natural gas from conventional reservoirs. In 2010, we drilled 20 gross wells in this area.
 
Granite Wash — The Granite Wash is concentrated in Hemphill and Wheeler counties in the Texas Panhandle and in western Oklahoma. Our average working interest is approximately 48% and we hold approximately 60,000 net acres of land. The Granite Wash wells produce liquids and natural gas from conventional reservoirs. In 2010, we drilled 29 gross wells in this area and plan to drill approximately 55 gross wells in 2011.
 
Haynesville-Bossier Shale — Our Haynesville Shale acreage position spans across east Texas and north Louisiana with an average working interest of 92%. To date, our drilling activity has been focused on approximately 150,000 acres located in Panola, Shelby and San Augustine counties in east Texas. We drilled 23 gross wells in 2010.
 
Canada
 
Jackfish — Jackfish is our 100%-owned thermal heavy oil project in the non-conventional oil sands of east central Alberta. We are employing steam-assisted gravity drainage at Jackfish. The first phase of Jackfish is fully operational with a gross facility capacity of 35 MBbls per day. We expect this project to maintain a flat production profile for greater than 20 years at an average net production rate of approximately 25-30 MBbls per day. We have completed construction of the second phase of Jackfish and we have filed a regulatory application for a third phase. The second and third phases of Jackfish are each expected to eventually produce approximately 30 MBbls per day of heavy oil production net of royalties over the life of the projects.
 
Northwest — The Northwest region includes acreage within west central Alberta and northeast British Columbia. We hold approximately 1.9 million net acres in the region, which produces primarily natural gas


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from conventional reservoirs. Our average working interest in the area is approximately 73%. In 2010, we drilled 67 gross wells and plan to drill about 50 gross wells in 2011.
 
Lloydminster — Our Lloydminster properties are located to the south and east of Jackfish in eastern Alberta and western Saskatchewan. Lloydminster produces heavy oil by conventional means without steam injection. We hold 2.4 million net acres and have an 89% average working interest in our Lloydminster properties. In 2010, we drilled 181 gross wells and plan to drill a similar amount of gross wells in 2011.
 
Deep Basin — Our properties in Canada’s Deep Basin include portions of west central Alberta and east central British Columbia. We hold approximately 520,000 net acres in the Deep Basin. The area produces natural gas and liquids from conventional reservoirs. Our average working interest in the Deep Basin is 43%. In 2010, we drilled 39 gross wells and plan to drill approximately 30 gross wells in 2011.
 
Horn River Basin — The Horn River Basin, located in northeast British Columbia, is a non-conventional gas reservoir targeting the Devonian Shale. Our leases include approximately 170,000 net acres with a 100% working interest. We drilled 7 gross wells in 2010.
 
Pike — Our 50%-owned Pike oil sands acreage is situated directly to the south of our Jackfish acreage in east central Alberta. This position was attained in 2010 through a joint venture agreement with BP. The Pike leasehold is currently undeveloped and has no proved reserves or production as of December 31, 2010. We began appraisal drilling near the end of 2010 and are acquiring seismic data. The drilling results and seismic will help us determine the optimal configuration for the initial phase of development. We expect to begin the regulatory application process for the first Pike phase around the end of 2011.
 
Preparation of Reserves Estimates and Reserves Audits
 
Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from known reservoirs under existing economic conditions, operating methods and government regulations. To be considered proved, oil and gas reserves must be economically producible before contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain. Also, the project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
 
The process of estimating oil, gas and NGL reserves is complex and requires significant judgment as discussed in “Item 1A. Risk Factors.” As a result, we have developed internal policies for estimating and recording reserves. Our policies regarding booking reserves require proved reserves to be in compliance with the SEC definitions and guidance. Our policies assign responsibilities for compliance in reserves bookings to our Reserve Evaluation Group (the “Group”). These same policies also require that reserve estimates be made by professionally qualified reserves estimators (“Qualified Estimators”), as defined by the Society of Petroleum Engineers’ standards.
 
The Group, which is led by Devon’s Director of Reserves and Economics, is responsible for the internal review and certification of reserves estimates. We ensure the Group’s Director and key members of the Group have appropriate technical qualifications to oversee the preparation of reserves estimates. Such qualifications include any or all of the following:
 
  •  an undergraduate degree in petroleum engineering from an accredited university, or equivalent;
 
  •  a petroleum engineering license, or similar certification;
 
  •  memberships in oil and gas industry or trade groups; and
 
  •  relevant experience estimating reserves.
 
The current Director of the Group has all of the qualifications listed above. The current Director has been involved with reserves estimation in accordance with SEC definitions and guidance since 1987. He has experience in reserves estimation for projects in the United States (both onshore and offshore), as well as in Canada, Asia, the Middle East and South America. He has been employed by Devon for the past ten years,


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including the past three in his current position as Director of Reserves and Economics. During his career with Devon and others, he was the primary reservoir engineer for projects including, but not limited to:
 
  •  Hugoton Gas Field (Kansas)
 
  •  Sho-Vel-Tum CO2 Flood (Oklahoma)
 
  •  West Loco Hills Unit Waterflood and CO2 Flood (New Mexico)
 
  •  Dagger Draw Oil Field (New Mexico)
 
  •  Clarke Lake Gas Field (Alberta, Canada)
 
  •  Panyu 4-2 and 5-1 Joint Development (Offshore South China Sea)
 
  •  ACG Unit (Caspian Sea)
 
As the primary reservoir engineer, he was responsible for reserves estimation on each of these projects. These reserves estimates were utilized internally and for SEC filings.
 
From 2003 to 2010, he served as the reservoir engineering representative on our internal Peer Review Team, reviewing reserves and resource estimates for projects including, but not limited to:
 
  •  Mobile Bay Norphlet Discoveries (Gulf of Mexico Shelf)
 
  •  Cascade Lower Tertiary Development (Gulf of Mexico Deepwater)
 
  •  Polvo Development (Campos Basin, Brazil)
 
Additionally, the Group reports independently of any of our operating divisions. The Group’s Director reports to our Vice President of Budget and Reserves, who reports to our Chief Financial Officer. No portion of the Group’s compensation is directly dependent on the quantity of reserves booked.
 
Throughout the year, the Group performs internal audits of each operating division’s reserves. Selection criteria of reserves that are audited include major fields and major additions and revisions to reserves. In addition, the Group reviews reserve estimates with each of the third-party petroleum consultants discussed below. The Group also ensures our Qualified Estimators obtain continuing education related to the fundamentals of SEC proved reserves assignments.
 
The Group also oversees audits and reserves estimates performed by third-party consulting firms. During 2010, we engaged two such firms to audit a significant portion of our proved reserves. LaRoche Petroleum Consultants, Ltd. audited the 2010 reserve estimates for 94% of our U.S. onshore properties. AJM Petroleum Consultants audited 89% of our Canadian reserves.
 
Set forth below is a summary of the North American reserves that were evaluated, either by preparation or audit, by independent petroleum consultants for each of the years ended 2010, 2009 and 2008.
 
                                                 
    2010     2009     2008  
    Prepared     Audited     Prepared     Audited     Prepared     Audited  
 
U.S. Onshore
          94 %           93 %           92 %
U.S. Offshore
    N/A       N/A       100 %           100 %      
Total U.S. 
          94 %     5 %     89 %     5 %     87 %
Canada
          89 %           91 %           78 %
Total North America
          93 %     3 %     89 %     4 %     85 %
 
 
N/A Not applicable — We sold all our U.S. Offshore properties during 2010.
 
“Prepared” reserves are those quantities of reserves that were prepared by an independent petroleum consultant. “Audited” reserves are those quantities of reserves that were estimated by our employees and audited by an independent petroleum consultant. The Society of Petroleum Engineers’ definition of an audit is an examination of a company’s proved oil and gas reserves and net cash flow by an independent petroleum


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consultant that is conducted for the purpose of expressing an opinion as to whether such estimates, in aggregate, are reasonable and have been estimated and presented in conformity with generally accepted petroleum engineering and evaluation methods and procedures.
 
In addition to conducting these internal and external reviews, we also have a Reserves Committee that consists of three independent members of our Board of Directors. This committee provides additional oversight of our reserves estimation and certification process. The Reserves Committee assists the Board of Directors with its duties and responsibilities in evaluating and reporting our proved reserves, much like our Audit Committee assists the Board of Directors in supervising our audit and financial reporting requirements. Besides being independent, the members of our Reserves Committee also have educational backgrounds in geology or petroleum engineering, as well as experience relevant to the reserves estimation process.
 
The Reserves Committee meets a minimum of twice a year to discuss reserves issues and policies, and meets separately with our senior reserves engineering personnel and our independent petroleum consultants at those meetings. The responsibilities of the Reserves Committee include the following:
 
  •  approve the scope of and oversee an annual review and evaluation of our consolidated oil, gas and NGL reserves;
 
  •  oversee the integrity of our reserves evaluation and reporting system;
 
  •  oversee and evaluate, prepare and disclose our compliance with legal and regulatory requirements related to our oil, gas and NGL reserves;
 
  •  review the qualifications and independence of our independent engineering consultants; and
 
  •  monitor the performance of our independent engineering consultants.
 
Proved Oil, Natural Gas and NGL Reserves
 
The following table presents our estimated proved reserves by continent and for each significant country as of December 31, 2010. These estimates correspond with the method used in presenting the “Supplemental Information on Oil and Gas Operations” in Note 22 to our consolidated financial statements included in this report.
 
                                 
                Natural
       
    Oil
    Natural Gas
    Gas Liquids
    Total(1)
 
    (MMBbls)     (Bcf)     (MMBbls)     (MMBoe)  
 
Proved Reserves
                               
United States
    148       9,065       449       2,107  
Canada
    533       1,218       30       766  
                                 
Total North America
    681       10,283       479       2,873  
                                 
Proved Developed Reserves
                               
United States
    131       7,280       353       1,696  
Canada
    126       1,144       28       346  
                                 
Total North America
    257       8,424       381       2,042  
                                 
Proved Undeveloped Reserves
                               
United States
    17       1,785       96       411  
Canada
    407       74       2       420  
                                 
Total North America
    424       1,859       98       831  
                                 
 
 
(1) Gas reserves are converted to Boe at the rate of six Mcf per Bbl of oil, based upon the approximate relative energy content of gas and oil. This rate is not necessarily indicative of the relationship of natural gas and oil prices. Natural gas liquids reserves are converted to Boe on a one-to-one basis with oil.


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No estimates of our proved reserves have been filed with or included in reports to any federal or foreign governmental authority or agency since the beginning of 2010 except in filings with the SEC and the Department of Energy (“DOE”). Reserve estimates filed with the SEC correspond with the estimates of our reserves contained herein. Reserve estimates filed with the DOE are based upon the same underlying technical and economic assumptions as the estimates of our reserves included herein. However, the DOE requires reports to include the interests of all owners in wells that we operate and to exclude all interests in wells that we do not operate.
 
Proved Developed Reserves
 
As presented in the previous table, we had 2,042 MMBoe of proved developed reserves at December 31, 2010. Proved developed reserves consist of proved developed producing reserves and proved developed non-producing reserves. The following table provides additional information regarding our proved developed reserves at December 31, 2010.
 
                                 
                Natural
       
    Oil
    Natural Gas
    Gas Liquids
    Total(1)
 
    (MMBbls)     (Bcf)     (MMBbls)     (MMBoe)  
 
Proved Developed Producing Reserves
                               
United States
    123       6,702       318       1,557  
Canada
    116       1,031       25       314  
                                 
Total North America
    239       7,733       343       1,871  
                                 
Proved Developed Non-Producing Reserves
                               
United States
    8       578       35       139  
Canada
    10       113       3       32  
                                 
Total North America
    18       691       38       171  
                                 
 
 
(1) Gas reserves are converted to Boe at the rate of six Mcf per Bbl of oil, based upon the approximate relative energy content of gas and oil. This rate is not necessarily indicative of the relationship of natural gas and oil prices. Natural gas liquids reserves are converted to Boe on a one-to-one basis with oil.
 
Proved Undeveloped Reserves
 
The following table presents the changes in our total proved undeveloped reserves during 2010 (in MMBoe).
 
                 
Proved undeveloped reserves as of December 31, 2009
            811  
Extensions and discoveries
            145  
Revisions due to prices
            13  
Revisions other than price
            (8 )
Sale of reserves
            (39 )
Conversion to proved developed reserves
            (91 )
                 
Proved undeveloped reserves as of December 31, 2010
            831  
                 
 
At December 31, 2010, we had 831 MMBoe of proved undeveloped reserves. This represents a 2% increase as compared to 2009 and represents 29% of our total proved reserves. A large contributor to the increase was our 2010 drilling activities, which increased our proved undeveloped reserves 145 MMBoe. The divestiture of our Gulf of Mexico properties reduced our proved undeveloped reserves by 39 MMBoe.
 
As a result of 2010 development activities, we converted 91 MMBoe, or 11%, of the 2009 proved undeveloped reserves to proved developed reserves. This conversion rate implies a nine-year development cycle, which exceeds the five-year general guideline for recording proved undeveloped reserves. However, our


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overall proved undeveloped conversion rate is largely impacted by the pace of development at Jackfish. Excluding our Jackfish reserves, our 2010 proved undeveloped conversion rate implies a development cycle that approximates five years.
 
At December 31, 2010 and 2009, our Jackfish proved undeveloped reserves were 396 MMBoe and 351 MMBoe, respectively. Development schedules for the Jackfish reserves are primarily controlled by the need to keep the processing plants at their full capacity of 35,000 barrels of oil per day per facility. Processing plant capacity is controlled by factors such as total steam processing capacity, steam-oil ratios and air quality discharge permits. As a result, these reserves will remain classified as proved undeveloped for more than five years. Currently, the development schedule for these reserves extends though the year 2025. We have made significant funding commitments toward the development of the Jackfish reserves.
 
See Note 22 to the consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data” of this report for further discussion of the contributions by project area of all changes to total proved reserves.
 
Proved Reserves Cash Flows
 
The following table presents estimated cash flow information related to our December 31, 2010 estimated proved reserves. Similar to reserves, the cash flow estimates correspond with the method used in presenting the “Supplemental Information on Oil and Gas Operations” in Note 22 to our consolidated financial statements included in this report.
 
                         
    Total
    Proved
    Proved
 
    Proved
    Developed
    Undeveloped
 
    Reserves     Reserves     Reserves  
          (In millions)        
 
Pre-Tax Future Net Revenue(1)
                       
United States
  $ 27,650     $ 23,640     $ 4,010  
Canada
    19,173       7,222       11,951  
                         
Total North America
  $ 46,823     $ 30,862     $ 15,961  
                         
Pre-Tax 10% Present Value(1)
                       
United States
  $ 12,863     $ 12,093     $ 770  
Canada
    9,622       5,216       4,406  
                         
Total North America
  $ 22,485     $ 17,309     $ 5,176  
                         
Standardized Measure of Discounted Future Net Cash Flows(1)(2)
                       
United States
  $ 8,843                  
Canada
    7,509                  
                         
Total North America
  $ 16,352                  
                         
 
 
(1) Estimated pre-tax future net revenue represents estimated future revenue to be generated from the production of proved reserves, net of estimated production and development costs and site restoration and abandonment charges. The amounts shown do not give effect to depreciation, depletion and amortization, or to non-property related expenses such as debt service and income tax expense.
 
Future net revenues are calculated using prices that represent the average of the first-day-of-the-month price for the 12-month period prior to December 31, 2010. These prices were not changed except where different prices were fixed and determinable from applicable contracts. These assumptions yielded average prices over the life of our properties of $59.94 per Bbl of oil, $3.73 per Mcf of gas and $31.11 per Bbl of NGLs. The prices used in calculating the estimated future net revenues attributable to proved reserves do not necessarily reflect market prices for oil, gas and NGL production subsequent to December 31, 2010. There can be no assurance that all of the proved reserves will be produced and sold within the periods


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indicated, that the assumed prices will be realized or that existing contracts will be honored or judicially enforced.
 
The present value of after-tax future net revenues discounted at 10% per annum (“standardized measure”) was $16.4 billion at the end of 2010. Included as part of standardized measure were discounted future income taxes of $6.1 billion. Excluding these taxes, the present value of our pre-tax future net revenue (“pre-tax 10% present value”) was $22.5 billion. We believe the pre-tax 10% present value is a useful measure in addition to the after-tax standardized measure. The pre-tax 10% present value assists in both the determination of future cash flows of the current reserves as well as in making relative value comparisons among peer companies. The after-tax standardized measure is dependent on the unique tax situation of each individual company, while the pre-tax 10% present value is based on prices and discount factors, which are more consistent from company to company. We also understand that securities analysts use the pre-tax 10% present value measure in similar ways.
 
(2) See Note 22 to the consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data.”
 
Production, Production Prices and Production Costs
 
The following tables present our production and average sales prices by continent and for each significant field and country for the past three years.
 
                                 
    Year Ended December 31, 2010  
    Oil
    Natural Gas
    NGLs
    Total(1)
 
    (MMBbls)     (Bcf)     (MMBbls)     (MMBoe)  
 
Production
                               
Barnett Shale
    1       335       13       70  
Other United States fields
    15       381       15       93  
                                 
Total United States
    16       716       28       163  
                                 
Jackfish
    9                   9  
Other Canada fields
    16       214       4       56  
                                 
Total Canada
    25       214       4       65  
                                 
Total North America
    41       930       32       228  
                                 
 
                                 
    Oil
    Natural Gas
    NGLs
    Combined(1)
 
    (Per Bbl)     (Per Mcf)     (Per Bbl)     (Per Boe)  
 
Production Prices
                               
Barnett Shale
  $ 77.40     $ 3.55     $ 29.97     $ 23.48  
Total United States
  $ 75.81     $ 3.76     $ 30.86     $ 29.06  
Jackfish
  $ 52.51                 $ 52.51  
Total Canada
  $ 58.60     $ 4.11     $ 46.60     $ 39.11  
Total North America
  $ 65.14     $ 3.84     $ 32.61     $ 31.91  
 


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    Year Ended December 31, 2009  
    Oil
    Natural Gas
    NGLs
    Total(1)
 
    (MMBbls)     (Bcf)     (MMBbls)     (MMBoe)  
 
Production
                               
Barnett Shale
          331       13       69  
Other United States fields
    17       412       13       98  
                                 
Total United States
    17       743       26       167  
                                 
Jackfish
    8                   8  
Other Canada fields
    17       223       4       58  
                                 
Total Canada
    25       223       4       66  
                                 
Total North America
    42       966       30       233  
                                 
 
                                 
    Oil
    Natural Gas
    NGLs
    Combined(1)
 
    (Per Bbl)     (Per Mcf)     (Per Bbl)     (Per Boe)  
 
Production Prices
                               
Barnett Shale
  $ 58.78     $ 2.99     $ 22.36     $ 19.08  
Total United States
  $ 57.56     $ 3.20     $ 23.51     $ 23.71  
Jackfish
  $ 41.07                 $ 41.07  
Total Canada
  $ 47.35     $ 3.66     $ 33.09     $ 32.29  
Total North America
  $ 51.39     $ 3.31     $ 24.71     $ 26.15  
 
                                 
    Year Ended December 31, 2008  
    Oil
    Natural Gas
    NGLs
    Total(1)
 
    (MMBbls)     (Bcf)     (MMBbls)     (MMBoe)  
 
Production
                               
Barnett Shale
          321       12       66  
Other United States fields
    17       405       12       96  
                                 
Total United States
    17       726       24       162  
                                 
Jackfish
    4                   4  
Other Canada fields
    18       212       4       57  
                                 
Total Canada
    22       212       4       61  
                                 
Total North America
    39       938       28       223  
                                 
 
                                 
    Oil
    Natural Gas
    NGLs
    Combined(1)
 
    (Per Bbl)     (Per Mcf)     (Per Bbl)     (Per Boe)  
 
Production Prices
                               
Barnett Shale
  $ 97.23     $ 7.38     $ 39.34     $ 43.71  
Total United States
  $ 98.83     $ 7.59     $ 41.21     $ 50.55  
Jackfish
  $ 50.67                 $ 50.67  
Total Canada
  $ 71.04     $ 8.17     $ 61.45     $ 57.65  
Total North America
  $ 83.35     $ 7.73     $ 44.08     $ 52.49  
 
 
(1) Gas reserves are converted to Boe at the rate of six Mcf per Bbl of oil, based upon the approximate relative energy content of gas and oil. This rate is not necessarily indicative of the relationship of natural gas and oil prices. Natural gas liquids reserves are converted to Boe on a one-to-one basis with oil.

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The following table presents our production cost per Boe by continent and for each significant field and country for the past three years. Production costs do not include ad valorem or severance taxes.
 
                         
    Year Ended December 31,  
    2010     2009     2008  
 
Barnett Shale
  $ 3.87     $ 3.96     $ 4.34  
Total United States
  $ 5.47     $ 5.97     $ 6.62  
Jackfish
  $ 16.81     $ 12.75     $ 28.93  
Total Canada
  $ 12.37     $ 10.15     $ 12.74  
Total North America
  $ 7.42     $ 7.16     $ 8.29  
 
Drilling Activities and Results
 
The following tables summarize our development and exploratory drilling results for the past three years.
 
                                                 
    Year Ended December 31, 2010  
    Development Wells(1)     Exploratory Wells(1)     Total Wells(1)  
    Productive     Dry     Productive     Dry     Productive     Dry  
 
U.S. Onshore
    853.2       5.3       23.4       1.5       876.6       6.8  
U.S. Offshore
    2.5                         2.5        
                                                 
Total U.S.
    855.7       5.3       23.4       1.5       879.1       6.8  
Canada
    267.8             41.9       1.0       309.7       1.0  
                                                 
Total North America
    1,123.5       5.3       65.3       2.5       1,188.8       7.8  
                                                 
 
                                                 
    Year Ended December 31, 2009  
    Development Wells(1)     Exploratory Wells(1)     Total Wells(1)  
    Productive     Dry     Productive     Dry     Productive     Dry  
 
U.S. Onshore
    506.5       3.0       6.8       1.5       513.3       4.5  
U.S. Offshore
    1.5       0.8             0.5       1.5       1.3  
                                                 
Total U.S.
    508.0       3.8       6.8       2.0       514.8       5.8  
Canada
    307.2             28.2             335.4        
                                                 
Total North America
    815.2       3.8       35.0       2.0       850.2       5.8  
                                                 
 
                                                 
    Year Ended December 31, 2008  
    Development Wells(1)     Exploratory Wells(1)     Total Wells(1)  
    Productive     Dry     Productive     Dry     Productive     Dry  
 
U.S. Onshore
    1,024.0       17.5       12.8       2.0       1,036.8       19.5  
U.S. Offshore
    9.0       1.0       0.8       1.8       9.8       2.8  
                                                 
Total U.S.
    1,033.0       18.5       13.6       3.8       1,046.6       22.3  
Canada
    528.9       3.2       50.1       3.3       579.0       6.5  
                                                 
Total North America
    1,561.9       21.7       63.7       7.1       1,625.6       28.8  
                                                 
 
 
(1) These well counts represent net wells completed during each year. Net wells are gross wells multiplied by our fractional working interests on the well.


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The following table presents the results, as of February 1, 2011, of our wells that were in progress as of December 31, 2010.
 
                                                                 
    Productive     Dry     Still in Progress     Total  
    Gross(1)     Net(2)     Gross(1)     Net(2)     Gross(1)     Net(2)     Gross(1)     Net(2)  
 
U.S.
    47       31.5                   193       128.8       240       160.3  
Canada
    9       6.9                   4       3.0       13       9.9  
                                                                 
Total North America
    56       38.4                   197       131.8       253       170.2  
                                                                 
 
 
(1) Gross wells are the sum of all wells in which we own an interest.
 
(2) Net wells are gross wells multiplied by our fractional working interests on the well.
 
Well Statistics
 
The following table sets forth our producing wells as of December 31, 2010.
 
                                                 
    Oil Wells     Natural Gas Wells     Total Wells  
    Gross(1)     Net(2)     Gross(1)     Net(2)     Gross(1)     Net(2)  
 
U.S.
    7,864       2,741       19,719       13,125       27,583       15,866  
Canada
    4,980       3,798       5,534       3,258       10,514       7,056  
                                                 
Total North America
    12,844       6,539       25,253       16,383       38,097       22,922  
                                                 
 
 
(1) Gross wells are the sum of all wells in which we own an interest.
 
(2) Net wells are gross wells multiplied by our fractional working interests on the well.
 
Acreage Statistics
 
The following table sets forth our developed and undeveloped oil and gas lease and mineral acreage as of December 31, 2010. The acreage in the table below includes 1.4 million, 0.5 million and 0.9 million net acres subject to leases that are scheduled to expire during 2011, 2012 and 2013, respectively.
 
                                                 
    Developed     Undeveloped     Total  
    Gross(1)     Net(2)     Gross(1)     Net(2)     Gross(1)     Net(2)  
    (In thousands)  
 
U.S.
    3,249       2,179       6,683       3,806       9,932       5,985  
Canada
    3,647       2,258       7,571       5,013       11,218       7,271  
                                                 
Total North America
    6,896       4,437       14,254       8,819       21,150       13,256  
                                                 
 
 
(1) Gross acres are the sum of all acres in which we own an interest.
 
(2) Net acres are gross acres multiplied by our fractional working interests on the acreage.
 
Operation of Properties
 
The day-to-day operations of oil and gas properties are the responsibility of an operator designated under pooling or operating agreements. The operator supervises production, maintains production records, employs field personnel and performs other functions.
 
We are the operator of 23,056 of our wells. As operator, we receive reimbursement for direct expenses incurred in the performance of our duties as well as monthly per-well producing and drilling overhead reimbursement at rates customarily charged in the area. In presenting our financial data, we record the monthly overhead reimbursements as a reduction of general and administrative expense, which is a common industry practice.


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Title to Properties
 
Title to properties is subject to contractual arrangements customary in the oil and gas industry, liens for current taxes not yet due and, in some instances, other encumbrances. We believe that such burdens do not materially detract from the value of such properties or from the respective interests therein or materially interfere with their use in the operation of the business.
 
As is customary in the industry, other than a preliminary review of local records, little investigation of record title is made at the time of acquisitions of undeveloped properties. Investigations, which generally include a title opinion of outside counsel, are made prior to the consummation of an acquisition of producing properties and before commencement of drilling operations on undeveloped properties.
 
Item 3.   Legal Proceedings
 
We are involved in various routine legal proceedings incidental to our business. However, to our knowledge as of the date of this report, there were no material pending legal proceedings to which we are a party or to which any of our property is subject.
 
Item 4.   Submission of Matters to a Vote of Security Holders
 
There were no matters submitted to a vote of security holders during the fourth quarter of 2010.


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PART II
 
Item 5.   Market for Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
 
Our common stock is traded on the New York Stock Exchange (the “NYSE”). On February 10, 2011, there were 12,704 holders of record of our common stock. The following table sets forth the quarterly high and low sales prices for our common stock as reported by the NYSE during 2010 and 2009. Also, included are the quarterly dividends per share paid during 2010 and 2009. We began paying regular quarterly cash dividends on our common stock in the second quarter of 1993. We anticipate continuing to pay regular quarterly dividends in the foreseeable future.
 
                         
    Price Range of Common Stock     Dividends
 
    High     Low     Per Share  
 
2010:
                       
Quarter Ended March 31, 2010
  $ 76.79     $ 62.38     $ 0.16  
Quarter Ended June 30, 2010
  $ 70.80     $ 58.58     $ 0.16  
Quarter Ended September 30, 2010
  $ 66.21     $ 59.07     $ 0.16  
Quarter Ended December 31, 2010
  $ 78.86     $ 63.76     $ 0.16  
2009:
                       
Quarter Ended March 31, 2009
  $ 73.11     $ 38.55     $ 0.16  
Quarter Ended June 30, 2009
  $ 67.40     $ 43.35     $ 0.16  
Quarter Ended September 30, 2009
  $ 72.91     $ 48.74     $ 0.16  
Quarter Ended December 31, 2009
  $ 75.05     $ 62.60     $ 0.16  


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Performance Graph
 
The following performance graph compares the yearly percentage change in the cumulative total shareholder return on Devon’s common stock with the cumulative total returns of the Standard & Poor’s 500 index (“the S&P 500 Index”) and the group of companies included in the Crude Petroleum and Natural Gas Standard Industrial Classification code (“the SIC Code”). The graph was prepared based on the following assumptions:
 
  •  $100 was invested on December 31, 2005 in Devon’s common stock, the S&P 500 Index and the SIC Code, and
 
  •  Dividends have been reinvested subsequent to the initial investment.
 
Comparison of 5-Year Cumulative Total Return
Devon, S&P 500 Index and SIC Code
 
 
The graph and related information shall not be deemed “soliciting material” or to be “filed” with the SEC, nor shall such information be incorporated by reference into any future filing under the Securities Act of 1933, as amended, or Securities Exchange Act of 1934, as amended, except to the extent that we specifically incorporate such information by reference into such a filing. The graph and information is included for historical comparative purposes only and should not be considered indicative of future stock performance.


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Issuer Purchases of Equity Securities
 
The following table provides information regarding purchases of our common stock that were made by us during the fourth quarter of 2010. All purchases were part of publicly announced plans or programs.
 
                         
                Maximum Dollar
 
                Value of Shares
 
    Total Number
          that May Yet Be
 
    of Shares
    Average Price
    Purchased Under the
 
Period
  Purchased(1)     Paid per Share     Plans or Programs(1)  
                (In millions)  
 
October 1 – October 31
    330,000     $ 65.64     $ 2,542  
November 1 – November 30
    348,400     $ 71.36     $ 2,517  
December 1 – December 31
    2,917,900     $ 74.82     $ 2,299  
                         
Total
    3,596,300     $ 73.64          
                         
 
 
(1) In May 2010, our Board of Directors approved a $3.5 billion share repurchase program. This program expires December 31, 2011. As of December 31, 2010, we had repurchased 18.3 million common shares for $1.2 billion, or $65.58 per share under this program.
 
New York Stock Exchange Certifications
 
This Form 10-K includes as exhibits the certifications of our Chief Executive Officer and Chief Financial Officer, required to be filed with the SEC pursuant to Section 302 of the Sarbanes Oxley Act of 2002. We have also filed with the New York Stock Exchange the 2010 annual certification of our Chief Executive Officer confirming that we have complied with the New York Stock Exchange corporate governance listing standards.
 
Item 6.   Selected Financial Data
 
The following selected financial information (not covered by the report of our independent registered public accounting firm) should be read in conjunction with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and the consolidated financial statements and the notes thereto included in “Item 8. Financial Statements and Supplementary Data.”
 
                                         
    Year Ended December 31,  
    2010     2009     2008     2007     2006  
    (In millions, except per share amounts)  
 
Revenues
  $ 9,940     $ 8,015     $ 13,858     $ 9,975     $ 9,143  
Earnings (loss) from continuing operations(1)
  $ 2,333     $ (2,753 )   $ (3,039 )   $ 2,485     $ 2,316  
Earnings (loss) per share from continuing operations — Basic
  $ 5.31     $ (6.20 )   $ (6.86 )   $ 5.56     $ 5.22  
Earnings (loss) per share from continuing operations — Diluted
  $ 5.29     $ (6.20 )   $ (6.86 )   $ 5.50     $ 5.15  
Cash dividends per common share
  $ 0.64     $ 0.64     $ 0.64     $ 0.56     $ 0.45  
Total assets(1)
  $ 32,927     $ 29,686     $ 31,908     $ 41,456     $ 35,063  
Long-term debt
  $ 3,819     $ 5,847     $ 5,661     $ 6,924     $ 5,568  
 
 
(1) During 2009 and 2008, we recorded noncash reductions of carrying value of oil and gas properties totaling $6.4 billion ($4.1 billion after income taxes) and $9.9 billion ($6.7 billion after income taxes), respectively, related to our continuing operations as discussed in Note 15 of the consolidated financial statements.


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Item 7.   Management’s Discussion and Analysis of Financial Condition and Results of Operations
 
Introduction
 
The following discussion and analysis presents management’s perspective of our business, financial condition and overall performance. This information is intended to provide investors with an understanding of our past performance, current financial condition and outlook for the future and should be reviewed in conjunction with our “Selected Financial Data” and “Financial Statements and Supplementary Data.” Our discussion and analysis relates to the following subjects:
 
  •  Overview of Business
 
  •  Overview of 2010 Results
 
  •  Business and Industry Outlook
 
  •  Results of Operations
 
  •  Capital Resources, Uses and Liquidity
 
  •  Contingencies and Legal Matters
 
  •  Critical Accounting Policies and Estimates
 
  •  Forward-Looking Estimates
 
Overview of Business
 
Devon is one of North America’s leading independent oil and gas exploration and production companies. Our operations are focused in the United States and Canada. We also own natural gas pipelines and treatment facilities in many of our producing areas, making us one of North America’s larger processors of natural gas liquids.
 
As an enterprise, we strive to optimize value for our shareholders by growing cash flows, earnings, production and reserves, all on a per debt-adjusted share basis. We accomplish this by replenishing our reserves and production and managing other key operational elements that drive our success. These items are discussed more fully below.
 
  •  Reserves and production growth — Our financial condition and profitability are significantly affected by the amount of proved reserves we own. Oil and gas properties are our most significant assets, and the reserves that relate to such properties are key to our future success. To increase our proved reserves, we must replace quantities produced with additional reserves from successful exploration and development activities or property acquisitions. Additionally, our profitability and operating cash flows are largely dependent on the amount of oil, gas and NGLs we produce. Growing production from existing properties is difficult because the rate of production from oil and gas properties generally declines as reserves are depleted. As a result, we constantly drill for and develop reserves on properties that provide a balance of near-term and long-term production. In addition, we may acquire properties with proved reserves that we can develop and subsequently produce to help create value.
 
  •  Capital investment discipline — Effectively deploying our resources into capital projects is key to maintaining and growing future production and oil and gas reserves. As a result, we have historically deployed virtually all our available cash flow into capital projects. Therefore, maintaining a disciplined approach to investing in capital projects is important to our profitability and financial condition. Our ability to control capital expenditures can be affected by changes in commodity prices. During times of high commodity prices, drilling and related costs often escalate due to the effects of supply versus demand economics. The inverse is also true.
 
  •  High return projects — We seek to invest our capital resources into projects where we can generate the highest risk-adjusted investment returns. One factor that can have a significant impact on such returns is our drilling success. Combined with appropriate revenue and cost-management strategies,


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  high drilling success rates are important to generating competitive returns on our capital investment. During 2010, we drilled 1,588 gross wells and 99% of those were successful. This success rate is similar to our drilling achievements in recent years, demonstrating a proven track record of success. By accomplishing high drilling success rates, we provide an inventory of reserves growth and a platform of opportunities on our undrilled acreage that can be profitably developed.
 
  •  Reserves and production balance — As evidenced by history, commodity prices are inherently volatile. In addition, oil and gas prices often diverge due to a variety of circumstances. Consequently, we value a balance of reserves and production between gas and liquids that can add stability to our revenue stream when either commodity price is under pressure. Our production mix in 2010 was approximately 68% gas and 32% oil and NGLs such as propane, butane and ethane. Our year-end reserves were approximately 60% gas and 40% liquids. With planned future growth in oil from Jackfish, Pike and other projects, combined with an inventory of shale natural gas plays, we expect to maintain this balance in the future.
 
  •  Operating cost controls — To maintain our competitive position, we must control our lease operating costs and other production costs. As reservoirs are depleted and production rates decline, per unit production costs will generally increase and affect our profitability and operating cash flows. Similar to capital expenditures, our ability to control operating costs can be affected by significant changes in commodity prices. Our base production is focused in core areas of our operations where we can achieve economies of scale to help manage our operating costs.
 
  •  Marketing and midstream performance improvement — We enhance the value of our oil and gas operations with our marketing and midstream business. By efficiently gathering and processing oil, gas and NGL production, our midstream operations enhance our project returns and contribute to our strategies to grow reserves and production and manage expenditures. Additionally, by effectively marketing our production, we maximize the prices received for our oil, gas and NGL production in relation to market prices. This is important because our profitability is highly dependent on market prices. These prices are determined primarily by market conditions. Market conditions for these products have been, and will continue to be, influenced by regional and worldwide economic and political conditions, weather, supply disruptions and other local market conditions that are beyond our control. To manage this volatility, we utilize financial hedging arrangements. As of February 10, 2011, approximately 29% of our 2011 gas production is associated with financial price swaps and fixed-price physicals. We also have basis swaps associated with 0.2 Bcf per day of our 2011 gas production. Additionally, approximately 36% of our 2011 oil production is associated with financial price collars. We also have call options that, if exercised, would relate to an additional 16% of our 2011 oil production.
 
  •  Financial flexibility preservation — As mentioned, commodity prices have been and will continue to be volatile and will continue to impact our profitability and cash flow. We understand this fact and manage our debt levels accordingly to preserve our liquidity and financial flexibility. We generally operate within the cash flow generated by our operations. However, during periods of low commodity prices, we may use our balance sheet strength to access debt or equity markets, allowing us to preserve our business and maintain momentum until markets recover. When prices improve, we can utilize excess operating cash flow to repay debt and invest in our activities that not only maintain but also increase value per share.
 
Overview of 2010 Results
 
2010 was an outstanding year for Devon. We reported record net earnings and reserves and made significant progress on our offshore divestiture program announced in November 2009. We sold our properties in the Gulf of Mexico, Azerbaijan, China and other International regions, generating $5.6 billion in after-tax proceeds and after-tax gains of $1.7 billion. Additionally, we have entered into agreements to sell our remaining offshore assets in Brazil and Angola and are waiting for the respective governments to approve the


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divestitures. Once the pending transactions are complete, we expect to have generated more than $8 billion in after-tax proceeds from all our divestitures.
 
These divestitures have allowed us to begin focusing entirely on our North American Onshore oil and natural gas portfolio. We grew North American Onshore production 1% in 2010 and replaced approximately 175% of our production with the drill bit at very attractive costs. The operational success we had with the drill bit increased our reserves to 2,873 MMBoe, the highest level in our history.
 
While our total North American Onshore production grew 1% in 2010, our oil and NGL production increased 6% over 2009. Liquids prices began to stabilize in 2009 and continued to strengthen throughout 2010. Although our realized price for gas increased 17% in 2010, gas prices continue to be weak. Considering the current and expected trends in commodity pricing, we have leveraged the value of our balanced portfolio and shifted capital spending toward the more profitable liquids-rich development opportunities currently available to us. The performance of these assets and higher price realizations are reflected in the 2010 earnings increase.
 
Key measures of our performance for 2010, as well as certain operational developments, are summarized below:
 
  •  North America Onshore oil and NGL production grew 6% over 2009, to 71 million Boe.
 
  •  North American Onshore gas production decreased 1% compared with 2009, to 152 million Boe.
 
  •  The combined realized price for oil, gas and NGLs per Boe increased 22% to $31.91.
 
  •  Oil, gas and NGL derivatives generated net gains of $811 million in 2010, including cash receipts of $888 million.
 
  •  Per unit lease operating costs increased 4% to $7.42 per Boe.
 
  •  Operating cash flow increased to $5.5 billion, representing a 16% increase over 2009.
 
  •  Capitalized costs incurred in our oil and gas activities were $6.5 billion in 2010. This includes $1.2 billion for unproved acreage acquisitions.
 
  •  Reserves increased to 2,873 MMBoe, an all-time high.
 
From an operational perspective, we completed another successful year with the drill-bit. We drilled 1,584 gross wells on our North America Onshore properties with a 99% success rate and grew our related proved reserves 9%.
 
During 2010, we more than doubled our industry-leading leasehold position in the liquids-rich Cana-Woodford shale play in western Oklahoma to more than 240,000 net acres. This allowed us to grow production more than 210% from the end of 2009 to the end of 2010. As a result of the success of our drilling and development efforts in the Cana-Woodford shale, we also constructed a gas processing plant in 2010.
 
In the Barnett Shale, we exited 2010 with production of 1.2 Bcfe per day, which includes 43 MBbls per day of liquids production. This represents a 16% increase in total production compared to the 2009 exit rate.
 
In the Permian Basin, we continued to assemble additional liquids-rich acreage. By the end of 2010, we had approximately one million net acres on liquids-rich development opportunities which led to an increase in production of 16% from the end of 2009 to the end of 2010.
 
Our net production from our Jackfish oil sands project in Canada averaged 25 MBbls per day. Jackfish continues to be one of Canada’s most successful steam-assisted gravity drainage projects. Construction of our second Jackfish project is now complete. We expect to have first oil production by the end of 2011. Additionally, we applied for regulatory approval of a third phase of Jackfish in 2010.
 
During 2010, we used a portion of our offshore divestiture proceeds to invest $1.2 billion in unproved leasehold acquisition focused on oil and liquids-rich gas plays. Our most significant single investment was our $500 million acquisition of a 50% interest in the Pike oil sands. The Pike acreage lies immediately adjacent to


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the Jackfish project. We began appraisal drilling at Pike near the end of 2010 and are acquiring seismic data. The drilling results and seismic will help us determine the optimal configuration for the initial phase of development. We expect to begin the regulatory application process for the first Pike phase around the end of 2011.
 
Our performance and offshore divestiture success throughout 2010 enabled us to end the year with a robust level of liquidity. At the end of 2010, we had $3.4 billion of cash and short-term investments and $2.6 billion of available credit.
 
Business and Industry Outlook
 
Even though we possess a great deal of financial strength and flexibility, we are fully committed to exercising capital discipline, maximizing profits, maintaining balance sheet strength and optimizing growth per debt-adjusted share. Our portfolio of assets provides a great deal of investment flexibility. At the end of 2010, our proved reserves were comprised of approximately 60% gas and 40% liquids. While gas prices remain challenged in the market, our near-term focus is on the oil and liquids-rich opportunities that exist within our balanced portfolio of properties. As a result, the vast majority of our 2011 drilling activity will be centered on our oil and liquids-rich gas properties. Should the outlook for commodity prices change, we have the flexibility to redirect our capital to ensure we continually focus on the highest-return assets in our portfolio.
 
Our ability to leverage the depth and breadth of our existing portfolio of properties will be key to the successful execution of our growth and value-creation objectives. With 2.9 billion Boe of proved reserves at the end of 2010, our North American onshore assets will provide many years of visible, economic growth and a good balance between liquids and natural gas. In 2011, we are targeting a 6-8% production increase. However, we expect this growth will be driven by oil and NGLs growth of at least 16%. Additionally, we will continue to use a portion of our offshore divestiture proceeds to repurchase common stock under our $3.5 billion share repurchase program. Therefore, our 2011 production growth will be even higher on a per debt-adjusted share basis.
 
Results of Operations
 
As previously stated, we are in the process of divesting our offshore assets. As a result, all amounts in this document related to our International operations are presented as discontinued. Therefore, the production, revenue and expense amounts presented in this “Results of Operations” section exclude amounts related to our International assets unless otherwise noted.
 
Even though we have divested our U.S. Offshore operations, these properties do not qualify as discontinued operations under accounting rules. As such, financial and operating data provided in this document that pertain to our continuing operations include amounts related to our U.S. Offshore operations. To facilitate comparisons of our ongoing operations subsequent to the planned divestitures, we have presented amounts related to our U.S. Offshore assets separate from those of our North American Onshore assets where appropriate.


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Revenues
 
Our oil, gas and NGL production volumes are shown in the following table.
 
                                         
    Year Ended December 31,  
          2010 vs.
          2009 vs.
       
    2010     2009(2)     2009     2008(2)     2008  
 
Oil (MMBbls)
                                       
U.S. Onshore
    14       +17 %     12       +3 %     11  
Canada
    25       −1 %     25       +17 %     22  
                                         
North America Onshore
    39       +5 %     37       +12 %     33  
U.S. Offshore
    2       −62 %     5       −15 %     6  
                                         
Total
    41       −3 %     42       +8 %     39  
                                         
Gas (Bcf)
                                       
U.S. Onshore
    699       +0 %     698       +5 %     669  
Canada
    214       −4 %     223       +5 %     212  
                                         
North America Onshore
    913       −1 %     921       +5 %     881  
U.S. Offshore
    17       −63 %     45       −22 %     57  
                                         
Total
    930       −4 %     966       +3 %     938  
                                         
NGLs (MMBbls)
                                       
U.S. Onshore
    28       +10 %     25       +9 %     24  
Canada
    4       −6 %     4       −5 %     4  
                                         
North America Onshore
    32       +8 %     29       +7 %     28  
U.S. Offshore
          −55 %     1       +27 %      
                                         
Total
    32       +6 %     30       +7 %     28  
                                         
Total (MMBoe)(1)
                                       
U.S. Onshore
    158       +3 %     154       +5 %     146  
Canada
    65       −3 %     66       +9 %     61  
                                         
North America Onshore
    223       +1 %     220       +6 %     207  
U.S. Offshore
    5       −62 %     13       −18 %     16  
                                         
Total
    228       −2 %     233       +4 %     223  
                                         
 
 
(1) Gas volumes are converted to Boe at the rate of six Mcf of gas per barrel of oil, based upon the approximate relative energy content of gas and oil, which rate is not necessarily indicative of the relationship of gas and oil prices. NGL volumes are converted to Boe on a one-to-one basis with oil.
 
(2) All percentage changes included in this table are based on actual figures and not the rounded figures included in the table.


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The following table presents the prices we realized on our production volumes. These prices exclude any effects due to our oil, gas and NGL derivatives.
 
                                         
    Year Ended December 31,  
          2010 vs.
          2009 vs.
       
    2010     2009     2009     2008     2008  
 
Oil (per Bbl)
                                       
U.S. Onshore
  $ 75.53       +34 %   $ 56.17       −41 %   $ 95.63  
Canada
  $ 58.60       +24 %   $ 47.35       −33 %   $ 71.04  
North America Onshore
  $ 64.51       +29 %   $ 50.11       −37 %   $ 79.45  
U.S. Offshore
  $ 77.81       +28 %   $ 60.75       −42 %   $ 104.90  
Total
  $ 65.14       +27 %   $ 51.39       −38 %   $ 83.35  
Gas (per Mcf)
                                       
U.S. Onshore
  $ 3.73       +19 %   $ 3.14       −58 %   $ 7.43  
Canada
  $ 4.11       +12 %   $ 3.66       −55 %   $ 8.17  
North America Onshore
  $ 3.82       +17 %   $ 3.27       −57 %   $ 7.61  
U.S. Offshore
  $ 5.12       +22 %   $ 4.20       −56 %   $ 9.53  
Total
  $ 3.84       +16 %   $ 3.31       −57 %   $ 7.73  
NGLs (per Bbl)
                                       
U.S. Onshore
  $ 30.78       +32 %   $ 23.40       −43 %   $ 40.97  
Canada
  $ 46.60       +41 %   $ 33.09       −46 %   $ 61.45  
North America Onshore
  $ 32.55       +32 %   $ 24.65       −44 %   $ 43.94  
U.S. Offshore
  $ 38.22       +39 %   $ 27.42       −46 %   $ 51.11  
Total
  $ 32.61       +32 %   $ 24.71       −44 %   $ 44.08  
Combined (per Boe)(1)
                                       
U.S. Onshore
  $ 28.42       +27 %   $ 22.41       −53 %   $ 47.91  
Canada
  $ 39.11       +21 %   $ 32.29       −44 %   $ 57.65  
North America Onshore
  $ 31.52       +24 %   $ 25.38       —50 %   $ 50.78  
U.S. Offshore
  $ 49.06       +26 %   $ 38.83       −48 %   $ 74.55  
Total
  $ 31.91       +22 %   $ 26.15       −50 %   $ 52.49  
 
 
(1) Gas volumes are converted to Boe at the rate of six Mcf of gas per barrel of oil, based upon the approximate relative energy content of gas and oil, which rate is not necessarily indicative of the relationship of gas and oil prices. NGL volumes are converted to Boe on a one-to-one basis with oil.
 
The volume and price changes in the tables above caused the following changes to our oil, gas and NGL sales between 2008 and 2010.
 
                                 
    Oil     Gas     NGLs     Total  
    (In millions)  
 
2008 sales
  $ 3,233     $ 7,244     $ 1,243     $ 11,720  
Changes due to volumes
    258       222       89       569  
Changes due to prices
    (1,338 )     (4,269 )     (585 )     (6,192 )
                                 
2009 sales
    2,153       3,197       747       6,097  
Changes due to volumes
    (67 )     (122 )     46       (143 )
Changes due to prices
    557       497       254       1,308  
                                 
2010 sales
  $ 2,643     $ 3,572     $ 1,047     $ 7,262  
                                 


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Oil Sales
 
2010 vs. 2009 Oil sales increased $557 million as a result of a 27% increase in our realized price. The largest contributor to the increase in our realized price was the increase in the average NYMEX West Texas Intermediate index price over the same time period.
 
Oil sales decreased $67 million due to a three percent decrease in production. The decrease was comprised of the net effects of a 62% decrease in our U.S. Offshore production and a five percent increase in our North America Onshore production. The decrease in our U.S. Offshore production was primarily due to the divestiture of such properties in the second quarter of 2010. The increased North America Onshore production resulted primarily from continued development of our Permian Basin properties in Texas and our Jackfish thermal heavy oil project in Canada.
 
2009 vs. 2008 Oil sales decreased $1.3 billion as a result of a 38% decrease in our realized price without hedges. The largest contributor to the decrease in our realized price was the decrease in the average NYMEX West Texas Intermediate index price over the same time period.
 
Oil sales increased $258 million due to a three million barrel, or 8%, increase in production. The increased production resulted primarily from the continued development of Jackfish in Canada.
 
Gas Sales
 
2010 vs. 2009 Gas sales increased $497 million as a result of a 16% increase in our realized price without hedges. This increase was largely due to increases in the North American regional index prices upon which our gas sales are based.
 
A four percent decrease in production during 2010 caused gas sales to decrease by $122 million. The decrease was primarily due to the divestiture of our U.S. Offshore properties in the second quarter of 2010, as well as higher Canadian government royalties. Also, our other North America Onshore properties decreased one percent due to reduced drilling during most of 2009 in response to lower gas prices. As a result of the reduced drilling activities during 2009, natural declines of existing wells outpaced production gains from new drilling in 2010.
 
2009 vs. 2008 Gas sales decreased $4.3 billion as a result of a 57% decrease in our realized price without hedges. This decrease was largely due to decreases in the North American regional index prices upon which our gas sales are based.
 
A three percent increase in production during 2009 caused gas sales to increase by $222 million. Our North America Onshore properties contributed 40 Bcf of higher volumes. This increase included 25 Bcf of higher production in Canada due to a decline in Canadian government royalties, resulting largely from lower gas prices. The remainder of the North America Onshore growth resulted from new drilling and development that exceeded natural production declines, primarily in the Barnett Shale field in north Texas. These increases were partially offset by 12 Bcf of lower production from our U.S. Offshore properties, largely resulting from natural production declines.
 
NGL Sales
 
2010 vs. 2009 NGL sales increased $254 million during 2010 as a result of a 32% increase in our realized price. The increase was largely due to an increase in the Mont Belvieu, Texas index price over the same time period. NGL sales increased $46 million in 2010 due to a six percent increase in production. The increase in production was primarily due to increased drilling in North America Onshore areas that have liquids-rich gas.
 
2009 vs. 2008 NGL sales decreased $585 million as a result of a 44% decrease in our realized price. This decrease was largely due to a decrease in the Mont Belvieu, Texas index price over the same time period. NGL sales increased $89 million in 2009 due to a seven percent increase in production. The increase in production is primarily due to drilling and development in the Barnett Shale.


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Oil, Gas and NGL Derivatives
 
The following tables provide financial information associated with our oil, gas and NGL hedges. The first table presents the cash settlements and unrealized gains and losses recognized as components of our revenues. The subsequent tables present our oil, gas and NGL prices with, and without, the effects of the cash settlements. The prices do not include the effects of unrealized gains and losses.
 
                         
    Year Ended December 31,  
    2010     2009     2008  
    (In millions)  
 
Cash settlement receipts (payments):
                       
Gas derivatives
  $ 888     $ 505     $ (424 )
Oil derivatives
                27  
                         
Total cash settlements
    888       505       (397 )
                         
Unrealized gains (losses) on fair value changes:
                       
Gas derivatives
    12       (83 )     243  
Oil derivatives
    (91 )     (38 )      
NGL derivatives
    2              
                         
Total unrealized gains (losses) on fair value changes
    (77 )     (121 )     243  
                         
Oil, gas and NGL derivatives
  $ 811     $ 384     $ (154 )
                         
 
                                 
    Year Ended December 31, 2010  
    Oil
    Gas
    NGLs
    Total
 
    (Per Bbl)     (Per Mcf)     (Per Bbl)     (Per Boe)  
 
Realized price without hedges
  $ 65.14     $ 3.84     $ 32.61     $ 31.91  
Cash settlements of hedges
          0.96             3.90  
                                 
Realized price, including cash settlements
  $ 65.14     $ 4.80     $ 32.61     $ 35.81  
                                 
 
                                 
    Year Ended December 31, 2009  
    Oil
    Gas
    NGLs
    Total
 
    (Per Bbl)     (Per Mcf)     (Per Bbl)     (Per Boe)  
 
Realized price without hedges
  $ 51.39     $ 3.31     $ 24.71     $ 26.15  
Cash settlements of hedges
          0.52             2.16  
                                 
Realized price, including cash settlements
  $ 51.39     $ 3.83     $ 24.71     $ 28.31  
                                 
 
                                 
    Year Ended December 31, 2008  
    Oil
    Gas
    NGLs
    Total
 
    (Per Bbl)     (Per Mcf)     (Per Bbl)     (Per Boe)  
 
Realized price without hedges
  $ 83.35     $ 7.73     $ 44.08     $ 52.49  
Cash settlements of hedges
    0.70       (0.46 )           (1.78 )
                                 
Realized price, including cash settlements
  $ 84.05     $ 7.27     $ 44.08     $ 50.71  
                                 
 
Our oil, gas, and NGL derivatives include price swaps, costless collars and basis swaps. For the price swaps, we receive a fixed price for our production and pay a variable market price to the contract counterparty. The price collars set a floor and ceiling price. If the applicable monthly price indices are outside of the ranges set by the floor and ceiling prices in the various collars, we cash-settle the difference with the counterparty. For the basis swaps, we receive a fixed differential between two index prices and pay a variable differential on the same two index prices to the contract counterparty. Cash settlements presented in the tables above represent net realized gains or losses related to these various instruments.


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Additionally, to facilitate a portion of our price swaps, we have sold gas call options for 2012 and oil call options for 2011 and 2012. The call options give the counterparty the right to place us into a price swap at a predetermined fixed price. The terms of these call options are presented in “Item 7A. Quantitative and Qualitative Disclosures about Market Risk” of this report.
 
During 2010 and 2009, we received $888 million, or $0.96 per Mcf, and $505 million, or $0.52 per Mcf, respectively, from counterparties to settle our gas derivatives. During 2008, we paid $424 million, or $0.46 per Mcf to counterparties to settle our gas derivatives and received $27 million, or $0.70 per Bbl from counterparties to settle our oil derivatives. We had no settlements on NGL derivatives in any of these periods.
 
In addition to recognizing these cash settlement effects, we also recognize unrealized changes in the fair values of our oil, gas and NGL derivative instruments in each reporting period. We estimate the fair values of these derivatives primarily by using internal discounted cash flow calculations. We periodically validate our valuation techniques by comparing our internally generated fair value estimates with those obtained from contract counterparties or brokers.
 
The most significant variable to our cash flow calculations is our estimate of future commodity prices. We base our estimate of future prices upon published forward commodity price curves such as the Inside FERC Henry Hub forward curve for gas instruments and the NYMEX West Texas Intermediate forward curve for oil instruments. Based on the amount of volumes subject to our gas derivative financial instruments at December 31, 2010, a 10% increase in these forward curves would have decreased our 2010 unrealized gains by approximately $154 million. A 10% increase in the forward curves associated with our oil derivative financial instruments would have increased our 2010 unrealized losses by approximately $142 million. Another key input to our cash flow calculations is our estimate of volatility for these forward curves, which we base primarily upon implied volatility. Finally, the amount of production subject to oil, gas and NGL derivatives is not a variable in our cash flow calculations, but it does impact the total derivative values.
 
Counterparty credit risk is also a component of commodity derivative valuations. We have mitigated our exposure to any single counterparty by contracting with thirteen separate counterparties. Additionally, our derivative contracts generally require cash collateral to be posted if either our or the counterparty’s credit rating falls below investment grade. The mark-to-market exposure threshold, above which collateral must be posted, decreases as the debt rating falls further below investment grade. Such thresholds generally range from zero to $50 million for the majority of our contracts. As of December 31, 2010, the credit ratings of all our counterparties were investment grade.
 
Including the cash settlements discussed above, our oil, gas and NGL derivatives generated net gains of $811 million and $384 million during 2010 and 2009, respectively, and a net loss of $154 million during 2008. In addition to the impact of cash settlements, these net gains and losses were impacted by new positions and settlements that occurred during each period, as well as the relationships between contract prices and the associated forward curves. A summary of our outstanding oil, gas and NGL derivative positions as of December 31, 2010 is included in Item 7A. “Quantitative and Qualitative Disclosures About Market Risk” of this report.


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Marketing and Midstream Revenues and Operating Costs and Expenses
 
The details of the changes in marketing and midstream revenues, operating costs and expenses and the resulting operating profit are shown in the table below.
 
                                         
    Year Ended December 31,  
          2010 vs
          2009 vs
       
    2010     2009(1)     2009     2008(1)     2008  
    ($ in millions)  
 
Marketing and midstream:
                                       
Revenues
  $ 1,867       +22 %   $ 1,534       −33 %   $ 2,292  
Operating costs and expenses
    1,357       +33 %     1,022       −37 %     1,611  
                                         
Operating profit
  $ 510       −0 %   $ 512       −25 %   $ 681  
                                         
 
 
(1) All percentage changes included in this table are based on actual figures and not the rounded figures included in this table.
 
2010 vs. 2009 Marketing and midstream revenues increased $333 million and operating costs and expenses increased $335 million, causing operating profit to decrease $2 million. Both revenues and expenses increased primarily due to higher natural gas and NGL prices, partially offset by the effects of lower gas marketing profits.
 
2009 vs. 2008 Marketing and midstream revenues decreased $758 million and operating costs and expenses decreased $589 million, causing operating profit to decrease $169 million. Both revenues and expenses decreased primarily due to lower natural gas and NGL prices, partially offset by higher NGL production and gas pipeline throughput.
 
Lease Operating Expenses (“LOE”)
 
The details of the changes in LOE are shown in the table below.
 
                                         
    Year Ended December 31,  
          2010 vs.
          2009 vs.
       
    2010     2009(1)     2009     2008(1)     2008  
 
Lease operating expenses ($ in millions):
                                       
U.S. Onshore
  $ 832       −1 %   $ 838       −6 %   $ 893  
Canada
    797       +18 %     673       −13 %     776  
                                         
North American Onshore
    1,629       +8 %     1,511       −10 %     1,669  
U.S. Offshore
    60       −62 %     159       −13 %     182  
                                         
Total
  $ 1,689       +1 %   $ 1,670       −10 %   $ 1,851  
                                         
Lease operating expenses per Boe:
                                       
U.S. Onshore
  $ 5.26       −4 %   $ 5.46       −11 %   $ 6.11  
Canada
  $ 12.37       +22 %   $ 10.15       −20 %   $ 12.74  
North American Onshore
  $ 7.32       +7 %   $ 6.87       −15 %   $ 8.06  
U.S. Offshore
  $ 12.00       +0 %   $ 11.98       +6 %   $ 11.29  
Total
  $ 7.42       +4 %   $ 7.16       −14 %   $ 8.29  
 
 
(1) All percentage changes included in this table are based on actual figures and not the rounded figures included in this table.
 
2010 vs. 2009 LOE increased $19 million in 2010, which included a $118 million increase related to our North America Onshore operations and a $99 million decrease related to our U.S. Offshore operations. North America Onshore LOE increased $78 million due to changes in the exchange rate between the U.S. and


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Canadian dollars. The remainder of the increase in North America Onshore LOE is primarily due to increased costs related to our Jackfish operation in Canada. U.S. Offshore LOE decreased primarily due to property divestitures in the second quarter of 2010. The increase due to exchange rates was also the main contributor to the changes in North America Onshore and total LOE per Boe.
 
2009 vs. 2008 LOE decreased $181 million in 2009. LOE dropped $182 million due to declining costs for fuel, materials, equipment and personnel, as well as declines in maintenance and well workover projects. Such declines largely resulted from decreasing demand for field services due to lower oil and gas prices. Changes in the exchange rate between the U.S. and Canadian dollar reduced LOE $49 million. Additionally, LOE decreased $31 million as a result of hurricane damages in 2008 to certain of our U.S. Offshore facilities and transportation systems. These factors, excluding the hurricane damage, were also the main contributors to the decrease in LOE per Boe on our North America Onshore properties. Production growth at our large-scale Jackfish project also contributed to a decrease in LOE per Boe. As Jackfish production approached the facility’s capacity during 2009, its per-unit costs declined, contributing to lower overall LOE per Boe. The remainder of our four percent company-wide production growth added $81 million to LOE during 2009.
 
Taxes Other Than Income Taxes
 
Taxes other than income taxes consist primarily of production taxes and ad valorem taxes assessed by various government agencies on our U.S. Onshore properties. Production taxes are based on a percentage of production revenues that varies by property and government jurisdiction. Ad valorem taxes generally are based on property values as determined by the government agency assessing the tax. The following table details the changes in our taxes other than income taxes.
 
                                         
    Year Ended December 31,  
          2010 vs
          2009 vs
       
    2010     2009(1)     2009     2008(1)     2008  
    ($ in millions)  
 
Production
  $ 210       +59 %   $ 132       −57 %   $ 306  
Ad valorem
    165       −6 %     175       +8 %     162  
Other
    5       −30 %     7       −4 %     8  
                                         
Total
  $ 380       +21 %   $ 314       −34 %   $ 476  
                                         
 
 
(1) All percentage changes included in this table are based on actual figures and not the rounded figures included in this table.
 
2010 vs. 2009 Production taxes increased $78 million in 2010. This increase was largely due to higher U.S. Onshore revenues, as well as a decrease in production tax credits associated with certain properties in the state of Texas. Ad valorem taxes decreased $10 million primarily due to lower assessed values of our U.S. Onshore oil and gas property and equipment.
 
2009 vs. 2008 Production taxes decreased $174 million in 2009. This decrease was largely due to lower U.S. Onshore revenues, as well as an increase in production tax credits associated with certain properties in the state of Texas. Ad valorem taxes increased $13 million primarily due to higher assessed oil and gas property and equipment values.
 
Depreciation, Depletion and Amortization of Oil and Gas Properties (“DD&A”)
 
DD&A of oil and gas properties is calculated by multiplying the percentage of total proved reserve volumes produced during the year, by the “depletable base.” The depletable base represents our capitalized investment, net of accumulated DD&A and reductions of carrying value, plus future development costs related to proved undeveloped reserves. Generally, when reserve volumes are revised up or down, then the DD&A rate per unit of production will change inversely. However, when the depletable base changes, then the DD&A rate moves in the same direction. The per unit DD&A rate is not affected by production volumes. Absolute or total DD&A, as opposed to the rate per unit of production, generally moves in the same direction as production volumes. Oil and gas property DD&A is calculated separately on a country-by-country basis.


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The changes in our production volumes, DD&A rate per unit and DD&A of oil and gas properties are shown in the table below.
 
                                         
    Year Ended December 31,  
          2010 vs
          2009 vs
       
    2010     2009(1)     2009     2008(1)     2008  
 
Total production volumes (MMBoe)
    228       −2 %     233       +4 %     223  
DD&A rate ($ per Boe)
  $ 7.36       −6 %   $ 7.86       −40 %   $ 13.20  
                                         
DD&A expense ($ in millions)
  $ 1,675       −9 %   $ 1,832       −38 %   $ 2,948  
                                         
 
 
(1) All percentage changes included in this table are based on actual figures and not the rounded figures included in this table.
 
The following table details the changes in DD&A of oil and gas properties between 2008 and 2010 due to the changes in production volumes and DD&A rate presented in the table above (in millions).
 
         
2008 DD&A
  $ 2,948  
Change due to volumes
    130  
Change due to rate
    (1,246 )
         
2009 DD&A
    1,832  
Change due to volumes
    (43 )
Change due to rate
    (114 )
         
2010 DD&A
  $ 1,675  
         
 
2010 vs. 2009 Oil and gas property-related DD&A decreased $114 million during 2010 due to a six percent decrease in the DD&A rate. The largest contributors to the rate decrease were our 2010 U.S. Offshore property divestitures and a reduction of the carrying value of our United States oil and gas properties recognized in the first quarter of 2009. This reduction totaled $6.4 billion and resulted from a full cost ceiling limitation. These decreases were partially offset by the effects of costs incurred and the transfer of previously unproved costs to the depletable base as a result of 2010 drilling and development activities, as well as changes in the exchange rate between the U.S. and Canadian dollars.
 
2009 vs. 2008 Oil and gas property related DD&A decreased $1.2 billion due to a 40% decrease in the DD&A rate. The largest contributors to the rate decrease were reductions of the carrying values of certain of our oil and gas properties recognized in the first quarter of 2009 and the fourth quarter of 2008. These reductions totaled $16.3 billion and resulted from full cost ceiling limitations in the United States and Canada. In addition, the effects of changes in the exchange rate between the U.S. and Canadian dollars also contributed to the rate decrease. These factors were partially offset by the effects of costs incurred and the transfer of previously unproved costs to the depletable base as a result of 2009 drilling activities. Partially offsetting the impact from the lower 2009 DD&A rate was our four percent production increase, which caused oil and gas property related DD&A expense to increase $130 million.
 
The impact of adopting the SEC’s new Modernization of Oil and Gas Reporting rules at the end of 2009 had virtually no impact on our DD&A rate.
 
General and Administrative Expenses (“G&A”)
 
Our net G&A consists of three primary components. The largest of these components is the gross amount of expenses incurred for personnel costs, office expenses, professional fees and other G&A items. The gross amount of these expenses is partially offset by two components. One is the amount of G&A capitalized pursuant to the full cost method of accounting related to exploration and development activities. The other is the amount of G&A reimbursed by working interest owners of properties for which we serve as the operator. These reimbursements are received during both the drilling and operational stages of a property’s life. The gross amount of G&A incurred, less the amounts capitalized and reimbursed, is recorded as net G&A in the


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consolidated statements of operations. Net G&A includes expenses related to oil, gas and NGL exploration and production activities, marketing and midstream activities, as well as corporate overhead activities. See the following table for a summary of G&A expenses by component.
 
                                         
    Year Ended December 31,  
          2010 vs
          2009 vs
       
    2010     2009(1)     2009     2008(1)     2008  
    ($ in millions)  
 
Gross G&A
  $ 987       −11 %   $ 1,107       +0 %   $ 1,103  
Capitalized G&A
    (311 )     −6 %     (332 )     −2 %     (337 )
Reimbursed G&A
    (113 )     −11 %     (127 )     +5 %     (121 )
                                         
Net G&A
  $ 563       −13 %   $ 648       +0 %   $ 645  
                                         
 
 
(1) All percentage changes included in this table are based on actual figures and not the rounded figures included in this table.
 
2010 vs. 2009 Gross G&A decreased $120 million largely due to a decline in employee severance costs. Such costs decreased primarily due to Gulf of Mexico employees that were impacted by the integration of our Gulf of Mexico and International operations into one offshore unit in the second quarter of 2009 and other employee departures during 2009. Gross G&A, as well as capitalized G&A, also decreased subsequent to our mid-year 2010 Gulf of Mexico divestitures as a result of the decline in our workforce. The Gulf of Mexico divestitures were also the main contributor to the decrease in G&A reimbursements. Gross and capitalized G&A also declined due to reduced spending initiatives for certain discretionary cost categories. These decreases were partially offset by an increase due to the effects of changes in the exchange rate between the U.S. and Canadian dollars.
 
2009 vs. 2008 Gross G&A increased $4 million. This increase was due to approximately $60 million of higher costs for employee compensation and benefits, mostly offset by the effects of our 2009 reduced spending initiatives for certain discretionary cost categories.
 
Employee cost increases in 2009 included an additional $57 million of severance costs. This increase was primarily due to Gulf of Mexico and other employee departures during 2009. Additionally, postretirement benefit costs increased approximately $50 million. The increases in employee costs were partially offset by a $27 million decrease due to accelerated share-based compensation expense recognized in 2008 resulting from a modification of certain executives compensation arrangements. The modified compensation arrangements provide that executives who meet certain years-of-service and age criteria can retire and continue vesting in outstanding share-based grants. Although this modification does not accelerate the vesting of the executives’ grants, it does accelerate the expense recognition as executives approach the years-of-service and age criteria.
 
Restructuring Costs
 
The following schedule includes the components of restructuring costs.
 
                                                 
    Year Ended December 31, 2010     Year Ended December 31, 2009  
    Continuing
    Discontinued
          Continuing
    Discontinued
       
    Operations     Operations     Total     Operations     Operations     Total  
    (In millions)  
 
Cash severance
  $ (17 )   $ 1     $ (16 )   $ 66     $ 24     $ 90  
Share-based awards
    (10 )     (5 )     (15 )     39       24       63  
Lease obligations
    70             70                    
Asset impairments
    11             11                    
Other
    3             3                    
                                                 
Restructuring costs
  $ 57     $ (4 )   $ 53     $ 105     $ 48     $ 153  
                                                 


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Employee Severance
 
In the fourth quarter of 2009, we recognized $153 million of estimated employee severance costs associated with the planned divestiture of our offshore assets that was announced in November 2009. This amount was based on estimates of the number of employees that would ultimately be impacted by the divestitures and included amounts related to cash severance costs and accelerated vesting of share-based grants. Of the $153 million total, $105 million related to our U.S. Offshore operations and the remainder related to our International discontinued operations.
 
During 2010, we divested all of our U.S. Offshore assets and a significant part of our International assets. As a result of these divestitures and associated employee terminations, we decreased our estimate of employee severance costs in 2010 by $31 million. More offshore employees than previously estimated received comparable positions with either the purchaser of the properties or in our U.S. Onshore operations, and this caused the $31 million decrease to our severance estimate. This decrease includes $27 million related to our U.S. Offshore operations and $4 million related to our International discontinued operations.
 
Lease Obligations
 
As a result of the divestitures discussed above, we ceased using certain office space that was subject to non-cancellable operating lease arrangements. Consequently, in 2010, we recognized $70 million of restructuring costs that represent the present value of our future obligations under the leases, net of anticipated sublease income. The estimate of lease obligations was based upon certain key estimates that could change over the term of the leases. These estimates include the estimated sublease income that we may receive over the term of the leases, as well as the amount of variable operating costs that we will be required to pay under the leases.
 
Asset Impairments
 
In 2010, we recognized $11 million of asset impairment charges for leasehold improvements and furniture associated with the office space we ceased using.
 
Interest Expense
 
The following schedule includes the components of interest expense.
 
                         
    Year Ended December 31,  
    2010     2009     2008  
    (In millions)  
 
Interest based on debt outstanding
  $ 408     $ 437     $ 426  
Capitalized interest
    (76 )     (94 )     (111 )
Early retirement of debt
    19              
Other
    12       6       14  
                         
Total interest expense
  $ 363     $ 349     $ 329  
                         
 
2010 vs. 2009 Interest based on debt outstanding decreased in 2010 primarily due to the retirement of $177 million of 10.125% notes upon their maturity in the fourth quarter of 2009 and the early redemption of our 7.25% senior notes as discussed below.
 
Capitalized interest decreased during 2010 primarily due to the divestitures of our U.S. Offshore properties during the first half of 2010, which was partially offset by higher capitalized interest associated with our Canadian oil sands development projects.
 
In the second quarter of 2010, we redeemed $350 million of 7.25% senior notes prior to their scheduled maturity of October 1, 2011. The notes were redeemed for $384 million, which represented 100 percent of the principal amount, a make-whole premium of $28 million and $6 million of accrued and unpaid interest. On the date of redemption, these notes also had an unamortized premium of $9 million. The $19 million presented


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in the table above represents the net of the $28 million make-whole premium and $9 million amortization of the remaining premium.
 
2009 vs. 2008 Interest based on debt outstanding increased $11 million from 2008 to 2009. This increase was primarily due to interest paid on the $500 million of 5.625% senior unsecured notes and $700 million of 6.30% senior unsecured notes that we issued in January 2009. This was partially offset by lower interest resulting from the retirement of our exchangeable debentures during the third quarter of 2008 and lower interest rates on our floating-rate commercial paper borrowings.
 
Capitalized interest decreased from 2008 to 2009 primarily due to the sales of our West African exploration and development properties in 2008 and the completion of the Access pipeline transportation system in Canada in the second quarter of 2008.
 
Interest-Rate and Other Financial Instruments
 
The details of the changes in our interest-rate and other financial instruments are shown in the table below.
 
                         
    Year Ended December 31,  
    2010     2009     2008  
    (In millions)  
 
(Gains) losses from:
                       
Interest rate swaps — cash settlements
  $ (44 )   $ (40 )   $ (1 )
Interest rate swaps — unrealized fair value changes
    30       (66 )     (104 )
Chevron common stock
                363  
Option embedded in exchangeable debentures
                (109 )
                         
Total
  $ (14 )   $ (106 )   $ 149  
                         
 
Interest Rate Swaps
 
During 2010, 2009 and 2008, we received cash settlements totaling $44 million, $40 million and $1 million, respectively, from counterparties to settle our interest rate swaps.
 
In addition to recognizing cash settlements, we recognize unrealized changes in the fair values of our interest rate swaps each reporting period. We estimate the fair values of our interest rate swap financial instruments primarily by using internal discounted cash flow calculations based upon forward interest-rate yields. We periodically validate our valuation techniques by comparing our internally generated fair value estimates with those obtained from contract counterparties or brokers. In 2010, we recorded an unrealized loss of $30 million as a result of changes in interest rates. In 2009 and 2008, we recorded unrealized gains of $66 million and $104 million, respectively, as a result of changes in interest rates.
 
The most significant variable to our cash flow calculations is our estimate of future interest rate yields. We base our estimate of future yields upon our own internal model that utilizes forward curves such as the LIBOR or the Federal Funds Rate provided by a third party. Based on the notional amount subject to the interest rate swaps at December 31, 2010, a 10% increase in these forward curves would have decreased our 2010 unrealized loss for our interest rate swaps by approximately $68 million.
 
Similar to our commodity derivative contracts, counterparty credit risk is also a component of interest rate derivative valuations. We have mitigated our exposure to any single counterparty by contracting with seven separate counterparties. Additionally, our derivative contracts generally require cash collateral to be posted if either our or the counterparty’s credit rating falls below investment grade. The mark-to-market exposure threshold, above which collateral must be posted, decreases as the debt rating falls further below investment grade. Such thresholds generally range from zero to $50 million for the majority of our contracts. The credit ratings of all our counterparties were investment grade as of December 31, 2010.


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Chevron Common Stock and Related Embedded Option
 
Until October 31, 2008, we owned 14.2 million shares of Chevron common stock and recognized unrealized changes in the fair value of this investment. On October 31, 2008, we exchanged these shares of Chevron common stock for Chevron’s interest in the Drunkard’s Wash properties located in east-central Utah and $280 million in cash. In accordance with the terms of the exchange, the fair value of our investment in the Chevron shares was estimated to be $67.71 per share on the exchange date. Prior to the exchange of these shares, we calculated the fair value of our investment in Chevron common stock using Chevron’s published market price.
 
We also recognized unrealized changes in the fair value of the conversion option embedded in the debentures exchangeable into shares of Chevron common stock. The embedded option was not actively traded in an established market. Therefore, we estimated its fair value using quotes obtained from a broker for trades occurring near the valuation date.
 
The loss during 2008 on our investment in Chevron common stock was directly attributable to a $25.62 per share decrease in the estimated fair value while we owned Chevron’s common stock during the year. The gain on the embedded option during 2008 was directly attributable to the change in fair value of the Chevron common stock from January 1, 2008 to the maturity date of August 15, 2008.
 
Reduction of Carrying Value of Oil and Gas Properties
 
During 2009 and 2008, we reduced the carrying values of certain of our oil and gas properties due to full cost ceiling limitations. A summary of these reductions and additional discussion is provided below.
 
                                 
    Year Ended December 31,  
    2009     2008  
          After
          After
 
    Gross     Taxes     Gross     Taxes  
    (In millions)  
 
United States
  $ 6,408     $ 4,085     $ 6,538     $ 4,168  
Canada
                3,353       2,488  
                                 
Total
  $ 6,408     $ 4,085     $ 9,891     $ 6,656  
                                 
 
The 2009 reduction was recognized in the first quarter and the 2008 reductions were recognized in the fourth quarter. The reductions resulted from significant decreases in each country’s full cost ceiling compared to the immediately preceding quarter. The lower United States ceiling value in the first quarter of 2009 largely resulted from the effects of declining natural gas prices subsequent to December 31, 2008. The lower ceiling values in the fourth quarter of 2008 largely resulted from the effects of sharp declines in oil, gas and NGL prices compared to September 30, 2008.
 
To demonstrate these declines, the March 31, 2009, December 31, 2008 and September 30, 2008 weighted average wellhead prices are presented in the following table.
 
                                                                         
    March 31, 2009     December 31, 2008     September 30, 2008  
    Oil
    Gas
    NGLs
    Oil
    Gas
    NGLs
    Oil
    Gas
    NGLs
 
Country
  (Per Bbl)     (Per Mcf)     (Per Bbl)     (Per Bbl)     (Per Mcf)     (Per Bbl)     (Per Bbl)     (Per Mcf)     (Per Bbl)  
 
United States
  $ 47.30     $ 2.67     $ 17.04     $ 42.21     $ 4.68     $ 16.16     $ 97.62     $ 5.28     $ 38.00  
Canada
    N/A       N/A       N/A     $ 23.23     $ 5.31     $ 20.89     $ 59.72     $ 6.00     $ 62.78  
 
 
N/A Not applicable.
 
The March 31, 2009 oil and gas wellhead prices in the table above compare to the NYMEX cash price of $49.66 per Bbl for crude oil and the Henry Hub spot price of $3.63 per MMBtu for gas. The December 31, 2008 oil and gas wellhead prices in the table above compare to the NYMEX cash price of $44.60 per Bbl for crude oil and the Henry Hub spot price of $5.71 per MMBtu for gas. The September 30, 2008, wellhead prices


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in the table compare to the NYMEX cash price of $100.64 per Bbl for crude oil and the Henry Hub spot price of $7.12 per MMBtu for gas.
 
Other, net
 
The following table includes the components of other, net.
 
                         
    Year Ended December 31,  
    2010     2009     2008  
    (In millions)  
 
Interest and dividend income
  $ (13 )   $ (8 )   $ (54 )
Deep water royalties
          (84 )      
Hurricane insurance proceeds
                (162 )
Other
    (32 )     24       (1 )
                         
Total
  $ (45 )   $ (68 )   $ (217 )
                         
 
Interest and dividend income decreased from 2008 to 2009 due to a decrease in dividends received on our previously owned investment in Chevron common stock and a decrease in interest received on cash equivalents due to lower rates and balances.
 
In 1995, the United States Congress passed the Deep Water Royalty Relief Act. The intent of this legislation was to encourage deep water exploration in the Gulf of Mexico by providing relief from the obligation to pay royalties on certain federal leases. Deep water leases issued in certain years by the Minerals Management Service (the “MMS”) have contained price thresholds, such that if the market prices for oil or gas exceeded the thresholds for a given year, royalty relief would not be granted for that year.
 
In October 2007, a federal district court ruled in favor of a plaintiff who had challenged the legality of including price thresholds in deep water leases. Additionally, in January 2009 a federal appellate court upheld this district court ruling. This judgment was later appealed to the United States Supreme Court, which, in October 2009, declined to review the appellate court’s ruling. The Supreme Court’s decision ended the MMS’s judicial course to enforce the price thresholds.
 
Prior to September 30, 2009, we had $84 million accrued for potential royalties on various deep water leases. Based upon the Supreme Court’s decision, we reduced to zero the $84 million loss contingency accrual in the third quarter of 2009.
 
In 2008, we recognized $162 million of excess insurance recoveries for damages suffered in 2005 related to hurricanes that struck the Gulf of Mexico. The excess recoveries resulted from business interruption claims on policies that were in effect when the 2005 hurricanes occurred.
 
Income Taxes
 
The following table presents our total income tax expense (benefit) and a reconciliation of our effective income tax rate to the U.S. statutory income tax rate.
 
                         
    Year Ended December 31,  
    2010     2009     2008  
 
Total income tax expense (benefit) (In millions)
  $ 1,235     $ (1,773 )   $ (1,121 )
                         
U.S. statutory income tax rate
    35 %     (35 )%     (35 )%
Repatriations and assumed repatriations
    4 %     1 %     7 %
State income taxes
    1 %     (2 )%     (1 )%
Taxation on Canadian operations
    (1 )%     (1 )%     5 %
Other
    (4 )%     (2 )%     (3 )%
                         
Effective income tax expense (benefit) rate
    35 %     (39 )%     (27 )%
                         


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During 2010 and 2009, pursuant to the completed and planned divestitures of our International assets located outside North America, a portion of our foreign earnings were no longer deemed to be permanently reinvested. Accordingly, we recognized deferred income tax expense of $144 million and $55 million during 2010 and 2009, respectively, related to assumed repatriations of earnings from certain of our foreign subsidiaries.
 
During 2008, we recognized $312 million of additional income tax expense that resulted from two related factors associated with our foreign operations. First, during 2008, we repatriated $2.6 billion from certain foreign subsidiaries to the United States. Second, we made certain tax policy election changes in the second quarter of 2008 to minimize the taxes we otherwise would pay for the cash repatriations, as well as the taxable gains associated with the sales of assets in West Africa. As a result of the repatriation and tax policy election changes, we recognized $295 million of additional current tax expense and $17 million of additional deferred tax expense. Excluding the $312 million of additional tax expense, our effective income tax benefit rate would have been 34% for 2008.
 
Earnings From Discontinued Operations
 
For all years presented in the following tables, our discontinued operations include amounts related to our assets in Azerbaijan, Brazil, China and other minor International properties. Additionally, during 2008, our discontinued operations included amounts related to our assets in West Africa, including Equatorial Guinea, Cote d’Ivoire, Gabon and other countries in the region until they were sold. Following are the components of earnings from discontinued operations.
 
                         
    Year Ended December 31,  
    2010     2009     2008  
 
Total production (MMBoe)
    10       16       18  
Combined price without hedges (per Boe)
  $ 72.68     $ 59.25     $ 92.72  
     
    (In millions)
Operating revenues
  $ 693     $ 945     $ 1,702  
                         
Expenses and other, net:
                       
Operating expenses
    212       496       776  
Restructuring costs
    (4 )     48        
Reduction of carrying value of oil and gas properties
          109       494  
Gain on sale of oil and gas properties
    (1,818 )     (17 )     (819 )
Other, net
    (82 )     (13 )     (7 )
                         
Total expenses and other, net
    (1,692 )     623       444  
                         
Earnings before income taxes
    2,385       322       1,258  
Income tax expense
    168       48       367  
                         
Earnings from discontinued operations
  $ 2,217     $ 274     $ 891  
                         


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The following table presents gains on our offshore and African divestiture transactions by year.
 
                                                 
    Year Ended December 31,  
    2010     2009     2008  
          After
          After
          After
 
    Gross     Taxes     Gross     Taxes     Gross     Taxes  
    (In millions)  
 
Azerbaijan
  $ 1,543     $ 1,524     $     $     $     $  
China — Panyu
    308       235                          
Equatorial Guinea
                            619       544  
Gabon
                            117       122  
Cote d’Ivoire
                17       17       83       95  
Other
    (33 )     (27 )                       8  
                                                 
Total
  $ 1,818     $ 1,732     $ 17     $ 17     $ 819     $ 769  
                                                 
 
2010 vs. 2009 Earnings increased $1.9 billion in 2010 primarily as a result of the $1.5 billion gain ($1.5 billion after taxes) from the divestiture of our Azerbaijan operations and the $308 million gain ($235 million after taxes) from the divestiture of our Panyu operations in China. Also, earnings increased $109 million due to the 2009 reductions of carrying value of our oil and gas properties, which primarily related to Brazil. The Brazilian reduction resulted largely from an exploratory well drilled at the BM-BAR-3 block in the offshore Barreirinhas Basin. After drilling this well in the first quarter of 2009, we concluded that the well did not have adequate reserves for commercial viability. As a result, the seismic, leasehold and drilling costs associated with this well contributed to the reduction recognized in the first quarter of 2009.
 
2009 vs. 2008 Earnings from discontinued operations decreased $617 million in 2009. Our discontinued earnings were impacted by several factors. First, operating revenues declined largely due to a 36% decrease in the price realized on our production, which was driven by a decline in crude oil index prices. Second, both operating revenues and expenses declined due to divestitures that closed in 2008. Earnings also decreased $752 million in 2009 due to larger gains recognized on West African asset divestitures in 2008.
 
Partially offsetting these decreased earnings in 2009 was the larger reduction of carrying value recognized in 2008 compared to 2009. The reductions largely consisted of full cost ceiling limitations related to our assets in Brazil that were caused by a decline in oil prices.
 
Capital Resources, Uses and Liquidity
 
The following discussion of capital resources, uses and liquidity should be read in conjunction with the consolidated financial statements included in “Financial Statements and Supplementary Data.”


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Sources and Uses of Cash
 
The following table presents the sources and uses of our cash and cash equivalents. The table presents capital expenditures on a cash basis. Therefore, these amounts differ from capital expenditure amounts that include accruals and are referred to elsewhere in this document. Additional discussion of these items follows the table.
 
                         
    2010     2009     2008  
    (In millions)  
 
Sources of cash and cash equivalents:
                       
Operating cash flow — continuing operations
  $ 5,022     $ 4,232     $ 8,448  
Divestitures of property and equipment
    4,310       34       117  
Cash distributed from discontinued operations
    2,864             1,898  
Commercial paper borrowings
          1,431       1  
Debt issuance, net of commercial paper repayments
          182        
Redemptions of long-term investments
    21       7       250  
Stock option exercises
    111       42       116  
Proceeds from exchange of Chevron stock
                280  
Other
    16       8       59  
                         
Total sources of cash and cash equivalents
    12,344       5,936       11,169  
                         
Uses of cash and cash equivalents:
                       
Capital expenditures
    (6,476 )     (4,879 )     (8,843 )
Commercial paper repayments
    (1,432 )            
Debt repayments
    (350 )     (178 )     (1,031 )
Net credit facility repayments
                (1,450 )
Repurchases of common stock
    (1,168 )           (665 )
Redemption of preferred stock
                (150 )
Dividends
    (281 )     (284 )     (289 )
Purchases of short-term investments
    (145 )            
Other
    (19 )     (17 )      
                         
Total uses of cash and cash equivalents
    (9,871 )     (5,358 )     (12,428 )
                         
Increase (decrease) from continuing operations
    2,473       578       (1,259 )
Increase (decrease) from discontinued operations, net of distributions to continuing operations
    (211 )     6       386  
Effect of foreign exchange rates
    17       43       (116 )
                         
Net increase (decrease) in cash and cash equivalents
  $ 2,279     $ 627     $ (989 )
                         
Cash and cash equivalents at end of year
  $ 3,290     $ 1,011     $ 384  
                         
Short-term investments at end of year
  $ 145     $     $  
                         
 
Operating Cash Flow — Continuing Operations
 
Net cash provided by operating activities (“operating cash flow”) continued to be a significant source of capital and liquidity in 2010. Changes in operating cash flow from our continuing operations are largely due to the same factors that affect our net earnings, with the exception of those earnings changes due to such noncash expenses as DD&A, financial instrument fair value changes, property impairments and deferred income taxes. As a result, our operating cash flow increased 19% during 2010 primarily due to the increase in revenues as discussed in the “Results of Operations” section of this report.


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During 2010, our operating cash flow funded approximately 78% of our cash payments for capital expenditures. However, our capital expenditures for 2010 included $500 million paid to form a heavy oil joint venture and acquire a 50 percent interest in the Pike oil sands in Alberta, Canada. This acquisition was completed in connection with the offshore divestitures discussed below. Excluding this $500 million acquisition, our operating cash flow funded approximately 84% of our capital expenditures during 2010. Offshore divestiture proceeds were used to fund the remainder of our cash-based capital expenditures.
 
During 2009, our operating cash flow funded approximately 87% of our cash payments for capital expenditures. Commercial paper borrowings were used to fund the remainder of our cash-based capital expenditures. During 2008, our capital expenditures were primarily funded by our operating cash flow and pre-existing cash balances.
 
Other Sources of Cash — Continuing and Discontinued Operations
 
As needed, we supplement our operating cash flow and available cash by accessing available credit under our senior credit facility and commercial paper program. We may also issue long-term debt to supplement our operating cash flow while maintaining adequate liquidity under our credit facilities. Additionally, we may acquire short-term investments to maximize our income on available cash balances. As needed, we reduce such short-term investment balances to further supplement our operating cash flow and available cash.
 
During 2010, we divested our U.S. Offshore, Azerbaijan, China and other minor international properties, generating $6.6 billion in pre-tax proceeds net of closing adjustments, or $5.6 billion after taxes. We have used proceeds from these divestitures to repay all our commercial paper borrowings, retire $350 million of other debt that was to mature in October 2011 and begin repurchasing our common shares. In addition, we began redeploying proceeds into our North America Onshore properties, including the $500 million Pike oil sands acquisition mentioned above.
 
During 2009, we issued $500 million of 5.625% senior unsecured notes due January 15, 2014 and $700 million of 6.30% senior unsecured notes due January 15, 2019. The net proceeds received of $1.187 billion, after discounts and issuance costs, were used primarily to repay Devon’s $1.005 billion of outstanding commercial paper as of December 31, 2008. Subsequent to the $1.005 billion commercial paper repayment in January 2009, we utilized additional commercial paper borrowings of $1.431 billion to fund capital expenditures in excess of our operating cash flow.
 
During 2008, we received $2.6 billion in pre-tax proceeds, or $1.9 billion after taxes and purchase price adjustments from sales of assets located in Equatorial Guinea and other West African countries. Also, in conjunction with these asset sales, we repatriated an additional $2.6 billion of earnings from certain foreign subsidiaries to the United States. We used these combined sources of cash in 2008 to fund debt repayments, common stock repurchases, redemptions of preferred stock and dividends on common and preferred stock. Additionally, we reduced our short-term investment balances by $250 million and received $280 million from the exchange of our investment in Chevron common stock.


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Capital Expenditures
 
Our capital expenditures are presented by geographic area and type in the following table. The amounts in the table below reflect cash payments for capital expenditures, including cash paid for capital expenditures incurred in prior periods. Capital expenditures actually incurred during 2010, 2009 and 2008 were approximately $6.9 billion, $4.7 billion and $10.0 billion, respectively.
 
                         
    2010     2009     2008  
    (In millions)  
 
U.S. Onshore
  $ 3,689     $ 2,413     $ 5,606  
Canada
    1,826       1,064       1,459  
                         
North American Onshore
    5,515       3,477       7,065  
U.S. Offshore
    376       845       1,157  
                         
Total exploration and development
    5,891       4,322       8,222  
Midstream
    236       323       451  
Other
    349       234       170  
                         
Total continuing operations
  $ 6,476     $ 4,879     $ 8,843  
                         
 
Our capital expenditures consist of amounts related to our oil and gas exploration and development operations, our midstream operations and other corporate activities. The vast majority of our capital expenditures are for the acquisition, drilling and development of oil and gas properties, which totaled $5.9 billion, $4.3 billion and $8.2 billion in 2010, 2009 and 2008, respectively. The increase in exploration and development capital spending in 2010 was partially due to the $500 million Pike oil sands acquisition mentioned above. Additionally, with rising oil and NGL prices and proceeds from our offshore divestiture program, we are increasing drilling primarily to grow liquids production across our North America Onshore portfolio of properties.
 
The decline in capital expenditures from 2008 to 2009 was due to decreased drilling activities in most of our operating areas in response to lower commodity prices in 2009 compared to previous years. Also, the 2008 capital expenditures include $2.6 billion related to acquisitions of properties in Texas, Louisiana, Oklahoma and Canada.
 
Capital expenditures for our midstream operations are primarily for the construction and expansion of natural gas processing plants, natural gas gathering and pipeline systems and oil pipelines. Our midstream capital expenditures in 2010 were largely impacted by reduced U.S. Onshore dry gas drilling activities.
 
Capital expenditures related to corporate activities increased in 2010. This increase is largely driven by the construction of our new headquarters in Oklahoma City.
 
Net Repayments of Debt
 
During 2010, we repaid $1.4 billion of commercial paper borrowings and redeemed $350 million of 7.25% senior notes prior to their scheduled maturity of October 1, 2011, primarily with proceeds received from our U.S. Offshore divestitures.
 
During 2009, we repaid our $177 million 10.125% notes upon maturity in the fourth quarter.
 
During 2008, we repaid $1.5 billion in outstanding credit facility borrowings primarily with proceeds received from the sales of assets under our African divestiture program. Also during 2008, virtually all holders of exchangeable debentures exercised their option to exchange their debentures for shares of Chevron common stock owned by us. The debentures matured on August 15, 2008. In lieu of delivering our shares of Chevron common stock, we exercised our option to pay the exchanging debenture holders cash totaling $1.0 billion. This amount included the retirement of debentures with a book value of $652 million and a $379 million payment of the related embedded derivative option.


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Repurchases of Common Stock
 
The following table summarizes our repurchases, including unsettled shares, under approved plans during 2010 and 2008 (amounts and shares in millions).
 
                                                 
    2010     2008  
Repurchase Program
  Amount     Shares     Per Share     Amount     Shares     Per Share  
 
2010 program
  $ 1,201       18.3     $ 65.58     $           $  
Annual program
                      178       2.0     $ 87.83  
2007 program
                      487       4.5     $ 109.25  
                                                 
Totals
  $ 1,201       18.3     $ 65.58     $ 665       6.5     $ 102.56  
                                                 
 
No shares were repurchased in 2009. The 2010 program expires on December 31, 2011 and the 2008 program and annual program expired on December 31, 2009.
 
Redemption of Preferred Stock
 
On June 20, 2008, we redeemed all 1.5 million outstanding shares of our 6.49% Series A cumulative preferred stock. Each share of preferred stock was redeemed for cash at a redemption price of $100 per share, plus accrued and unpaid dividends up to the redemption date.
 
Dividends
 
Devon paid common stock dividends of $281 million (or $0.64 per share) in 2010 and $284 million (or $0.64 per share) in both 2009 and 2008, respectively. Devon paid dividends of $5 million in 2008 to preferred stockholders. Devon redeemed its outstanding preferred stock in the second quarter of 2008.
 
Liquidity
 
Historically, our primary source of capital and liquidity has been operating cash flow. Additionally, we maintain revolving lines of credit and a commercial paper program, which can be accessed as needed to supplement operating cash flow. Other available sources of capital and liquidity include the issuance of equity and debt securities that can be issued pursuant to our automatically effective registration statement filed with the SEC. This registration statement can be used to offer short-term and long-term debt securities. Another major source of future liquidity will be proceeds from the sales of our remaining offshore assets in Brazil and Angola. We estimate the combination of these sources of capital will be adequate to fund future capital expenditures, share repurchases, debt repayments and other contractual commitments as discussed later in this section.
 
Operating Cash Flow
 
Our operating cash flow is sensitive to many variables, the most volatile of which is pricing of the oil, gas and NGLs produced. Due to improving oil and NGL prices, our operating cash flow increased approximately 16% to $5.5 billion in 2010 as compared to 2009. We expect operating cash flow to continue to be our primary source of liquidity.
 
Commodity Prices — Prices for oil, gas and NGLs are determined primarily by prevailing market conditions. Regional and worldwide economic activity, weather and other substantially variable factors influence market conditions for these products. These factors, which are difficult to predict, create volatility in oil, gas and NGL prices and are beyond our control. We expect this volatility to continue throughout 2011.
 
To mitigate some of the risk inherent in prices, we have utilized various price swap, fixed-price physical delivery and price collar contracts to set minimum and maximum prices on our 2011 production. As of February 10, 2011, approximately 29% of our 2011 gas production is associated with financial price swaps and fixed-price physicals. We also have basis swaps associated with 0.2 Bcf per day of our 2011 gas production. Additionally, approximately 36% of our 2011 oil production is associated with financial price


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collars. We also have call options that, if exercised, would hedge an additional 16% of our 2011 oil production.
 
Commodity prices can also affect our operating cash flow through an indirect effect on operating expenses. Significant commodity price increases can lead to an increase in drilling and development activities. As a result, the demand and cost for people, services, equipment and materials may also increase, causing a negative impact on our cash flow. However, the inverse is also true during periods of depressed commodity prices.
 
Interest Rates — Our operating cash flow can also be sensitive to interest rate fluctuations. As of February 10, 2011, we had total debt of $6.2 billion with an overall weighted average borrowing rate of 6.4%. To manage our exposure to interest rate volatility, we have interest rate swap instruments with a total notional amount of $2.1 billion. These consist of instruments with a notional amount of $1.15 billion in which we receive a fixed rate and pay a variable rate. The remaining instruments consist of forward starting swaps. Under the terms of the forward starting swaps, we will net settle these contracts in September 2011, or sooner should we elect, based upon us paying a fixed rate and receiving a floating rate. Including the effects of these swaps, the weighted-average interest rate related to our debt was 5.7% as of February 10, 2011.
 
Credit Losses — Our operating cash flow is also exposed to credit risk in a variety of ways. We are exposed to the credit risk of the customers who purchase our oil, gas and NGL production. We are also exposed to credit risk related to the collection of receivables from our joint-interest partners for their proportionate share of expenditures made on projects we operate. We are also exposed to the credit risk of counterparties to our derivative financial contracts as discussed previously in this report. We utilize a variety of mechanisms to limit our exposure to the credit risks of our customers, partners and counterparties. Such mechanisms include, under certain conditions, posting of letters of credit, prepayment requirements and collateral posting requirements.
 
Offshore Divestitures
 
During 2010, we sold our properties in the Gulf of Mexico, Azerbaijan, China and other International regions, generating $5.6 billion in after-tax proceeds. Additionally, we have entered into agreements to sell our remaining offshore assets in Brazil and Angola and are waiting for the respective governments to approve the divestitures. Once the pending transactions are complete, we expect to have generated more than $8 billion in after-tax proceeds. Similar to 2010, we expect to continue using the divestiture proceeds to invest in North America Onshore exploration and development opportunities, reduce our debt and repurchase our common shares.
 
Credit Availability
 
We have a $2.65 billion syndicated, unsecured revolving line of credit (the “Senior Credit Facility”) that can be accessed to provide liquidity as needed. The maturity date for $2.19 billion of the Senior Credit Facility is April 7, 2013. The maturity date for the remaining $0.46 billion is April 7, 2012. All amounts outstanding will be due and payable on the respective maturity dates unless the maturity is extended. Prior to each April 7 anniversary date, we have the option to extend the maturity of the Senior Credit Facility for one year, subject to the approval of the lenders. The Senior Credit Facility includes a revolving Canadian subfacility in a maximum amount of U.S. $500 million.
 
Amounts borrowed under the Senior Credit Facility may, at our election, bear interest at various fixed rate options for periods of up to twelve months. Such rates are generally less than the prime rate. However, we may elect to borrow at the prime rate.
 
We also have access to short-term credit under our commercial paper program. Total borrowings under the commercial paper program may not exceed $2.2 billion. Also, any borrowings under the commercial paper program reduce available capacity under the Senior Credit Facility on a dollar-for-dollar basis. Commercial paper debt generally has a maturity of between one and 90 days, although it can have a maturity of up to 365 days, and bears interest at rates agreed to at the time of the borrowing. The interest rate is based on a


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standard index such as the Federal Funds Rate, LIBOR, or the money market rate as found on the commercial paper market.
 
The Senior Credit Facility contains only one material financial covenant. This covenant requires us to maintain a ratio of total funded debt to total capitalization, as defined in the credit agreement, of no more than 65%. The credit agreement defines total funded debt as funds received through the issuance of debt securities such as debentures, bonds, notes payable, credit facility borrowings and short-term commercial paper borrowings. In addition, total funded debt includes all obligations with respect to payments received in consideration for oil, gas and NGL production yet to be acquired or produced at the time of payment. Funded debt excludes our outstanding letters of credit and trade payables. The credit agreement defines total capitalization as the sum of funded debt and stockholders’ equity adjusted for noncash financial writedowns, such as full cost ceiling impairments. As of December 31, 2010, we were in compliance with this covenant. Our debt-to-capitalization ratio at December 31, 2010, as calculated pursuant to the terms of the agreement, was 15.1%.
 
Our access to funds from the Senior Credit Facility is not restricted under any “material adverse effect” clauses. It is not uncommon for credit agreements to include such clauses. These clauses can remove the obligation of the banks to fund the credit line if any condition or event would reasonably be expected to have a material and adverse effect on the borrower’s financial condition, operations, properties or business considered as a whole, the borrower’s ability to make timely debt payments, or the enforceability of material terms of the credit agreement. While our credit facility includes covenants that require us to report a condition or event having a material adverse effect, the obligation of the banks to fund the credit facility is not conditioned on the absence of a material adverse effect.
 
The following schedule summarizes the capacity of our Senior Credit Facility by maturity date, as well as our available capacity as of February 10, 2011 (in millions).
 
                 
April 7, 2012 maturity
          $ 463  
April 7, 2013 maturity
            2,187  
                 
Total Senior Credit Facility
            2,650  
Less:
               
Outstanding credit facility borrowings
             
Outstanding commercial paper borrowings
            625  
Outstanding letters of credit
            39  
                 
Total available capacity
          $ 1,986  
                 
 
As presented in the table above, we had $625 million of commercial paper borrowings as of February 10, 2011. Although we ended 2010 with $3.4 billion of cash and short-term investments, the vast majority of this amount consists of proceeds from our International offshore divestitures. For the time being, we have decided not to repatriate these proceeds to the United States or permanently invest them in Canada. This decision is based on our ongoing evaluation of our future cash needs across our operations in the United States and Canada, as well as the relatively low borrowing rates on our short-term borrowings. If we do not repatriate these proceeds to the United States in the near-term, we may continue to increase our commercial paper borrowings to supplement our operating cash flow in funding our common stock repurchases and capital expenditures.
 
Debt Ratings
 
We receive debt ratings from the major ratings agencies in the United States. In determining our debt ratings, the agencies consider a number of items including, but not limited to, debt levels, planned asset sales, near-term and long-term production growth opportunities and capital allocation challenges. Liquidity, asset quality, cost structure, reserve mix, and commodity pricing levels are also considered by the rating agencies. Our current debt ratings are BBB+ with a stable outlook by both Fitch and Standard & Poor’s, and Baa1 with a stable outlook by Moody’s.


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There are no “rating triggers” in any of our contractual obligations that would accelerate scheduled maturities should our debt rating fall below a specified level. Our cost of borrowing under our Senior Credit Facility is predicated on our corporate debt rating. Therefore, even though a ratings downgrade would not accelerate scheduled maturities, it would adversely impact the interest rate on any borrowings under our Senior Credit Facility. Under the terms of the Senior Credit Facility, a one-notch downgrade would increase the fully-drawn borrowing costs from LIBOR plus 35 basis points to a new rate of LIBOR plus 45 basis points. A ratings downgrade could also adversely impact our ability to economically access debt markets in the future. As of December 31, 2010, we were not aware of any potential ratings downgrades being contemplated by the rating agencies.
 
Capital Expenditures
 
Our 2011 capital expenditures are expected to range from $5.4 billion to $6.0 billion. To a certain degree, the ultimate timing of these capital expenditures is within our control. Therefore, if commodity prices fluctuate from current estimates, we could choose to defer a portion of these planned 2011 capital expenditures until later periods, or accelerate capital expenditures planned for periods beyond 2011 to achieve the desired balance between sources and uses of liquidity. Based upon current price expectations for 2011, our existing commodity hedging contracts, available cash balances and credit availability, we anticipate having adequate capital resources to fund our 2011 capital expenditures.
 
Common Stock Repurchase Program
 
As a result of the success we have experienced with our offshore divestiture program, we announced a share repurchase program in May 2010. The program authorizes the repurchase of up to $3.5 billion of our common shares and expires December 31, 2011. As of February 10, 2011, we had repurchased $1.6 billion, or 23.5 million of our shares at an average price of $69.60. We will continue to use proceeds from our offshore divestiture program in 2011 to fund our repurchase program.
 
Contractual Obligations
 
A summary of our contractual obligations as of December 31, 2010, is provided in the following table.
 
                                         
    Payments Due by Period  
          Less Than
    1-3
    3-5
    More Than
 
    Total     1 Year     Years     Years     5 Years  
                (In millions)              
 
North American Onshore:
                                       
Purchase obligations(1)
  $ 7,710     $ 551     $ 1,471     $ 1,568     $ 4,120  
Debt(2)
    5,628       1,812       9       582       3,225  
Interest expense(3)
    4,645       392       544       502       3,207  
Drilling and facility obligations(4)
    1,163       747       410       6        
Firm transportation agreements(5)
    1,734       282       487       408       557  
Asset retirement obligations(6)
    1,497       74       102       110       1,211  
Lease obligations(7)
    489       58       104       77       250  
Other(8)
    389       59       141       156       33  
                                         
Total North America Onshore
    23,255       3,975       3,268       3,409       12,603  
                                         
Offshore:
                                       
Drilling and facility obligations(4)
    595       314       281              
Asset retirement obligations(6)
    24                   24        
Lease obligations(7)
    111       38       58       15        
                                         
Total Offshore
    730       352       339       39        
                                         
Grand Total
  $ 23,985     $ 4,327     $ 3,607     $ 3,448     $ 12,603  
                                         


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(1) Purchase obligation amounts represent contractual commitments to purchase condensate at market prices for use at our heavy oil projects in Canada. We have entered into these agreements because the condensate is an integral part of the heavy oil production process and any disruption in our ability to obtain condensate could negatively affect our ability to produce and transport heavy oil at these locations. Our total obligation related to condensate purchases expires in 2021. This value of the obligation in the table above is based on the contractual volumes and our internal estimate of future condensate market prices.
 
(2) Debt amounts represent scheduled maturities of our debt obligations at December 31, 2010, excluding $2 million of net premiums included in the carrying value of debt.
 
(3) Interest expense relates to our fixed-rate debt and represents the scheduled cash payments. We had no variable-rate debt outstanding as of December 31, 2010.
 
(4) Drilling and facility obligations represent contractual agreements with third-party service providers to procure drilling rigs and other related services for developmental and exploratory drilling and facilities construction. Our offshore commitment primarily relates to a long-term contract for a deepwater drilling rig being used in Brazil. Our lease and remaining commitments for this rig will be assumed by the buyer of our assets in Brazil when the associated divestiture transaction closes.
 
(5) Firm transportation agreements represent “ship or pay” arrangements whereby we have committed to ship certain volumes of oil, gas and NGLs for a fixed transportation fee. We have entered into these agreements to aid the movement of our production to market. We expect to have sufficient production to utilize these transportation services.
 
(6) Asset retirement obligations represent estimated discounted costs for future dismantlement, abandonment and rehabilitation costs. These obligations are recorded as liabilities on our December 31, 2010 balance sheet.
 
(7) Lease obligations for our North America onshore operations consist primarily of non-cancelable leases for office space and equipment used in our daily operations. Lease obligations for our offshore operations consist primarily of an FPSO in Brazil. The Polvo FPSO lease term expires in 2014. Our lease and remaining commitments for this FPSO will be assumed by the buyer of our assets in Brazil when the associated divestiture transaction closes.
 
(8) These amounts include $193 million related to uncertain tax positions. Expected pension funding obligations have not been included in this table, but are presented and discussed in the section immediately below.
 
Pension Funding and Estimates
 
Funded Status — As compared to the projected benefit obligation, our qualified and nonqualified defined benefit plans were underfunded by $492 million and $448 million at December 31, 2010 and 2009, respectively. A detailed reconciliation of the 2010 changes to our underfunded status is in Note 8 to the consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data” of this report. Of the $492 million underfunded status at the end of 2010, $198 million is attributable to various nonqualified defined benefit plans that have no plan assets. However, we have established certain trusts to fund the benefit obligations of such nonqualified plans. As of December 31, 2010, these trusts had investments with a fair value of $36 million. The value of these trusts is in noncurrent other assets in our consolidated balance sheets included in “Item 8. Financial Statements and Supplementary Data” of this report.
 
As compared to the accumulated benefit obligation, our qualified defined benefit plans were underfunded by $218 million at December 31, 2010. The accumulated benefit obligation differs from the projected benefit obligation in that the former includes no assumption about future compensation levels.
 
Our funding policy regarding the qualified defined benefit plans is to contribute the amounts necessary for the plans’ assets to approximately equal the present value of benefits earned by the participants, as calculated in accordance with the provisions of the Pension Protection Act. While we did have investment gains in 2010 and 2009, the investment losses experienced during 2008 significantly reduced the value of our


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plans’ assets. We estimate we will contribute approximately $84 million to our qualified pension plans during 2011. However, actual contributions may be different than this amount.
 
Our funding policy regarding the nonqualified defined benefit plans is to supplement as needed the amounts accumulated in the related trusts with available cash and cash equivalents.
 
Pension Estimate Assumptions — Our pension expense is recognized on an accrual basis over employees’ approximate service periods and is impacted by funding decisions or requirements. We recognized expense for our defined benefit pension plans of $85 million, $119 million and $61 million in 2010, 2009 and 2008, respectively. We estimate that our pension expense will approximate $91 million in 2011. Should our actual 2011 contributions to qualified and nonqualified plans vary significantly from our current estimate of $93 million, our actual 2011 pension expense could vary from this estimate.
 
The calculation of pension expense and pension liability requires the use of a number of assumptions. Changes in these assumptions can result in different expense and liability amounts, and actual experience can differ from the assumptions. We believe that the two most critical assumptions affecting pension expense and liabilities are the expected long-term rate of return on plan assets and the assumed discount rate.
 
We assumed that our plan assets would generate a long-term weighted average rate of return of 6.94% and 7.18% at December 31, 2010 and 2009, respectively. We developed these expected long-term rate of return assumptions by evaluating input from external consultants and economists as well as long-term inflation assumptions. The expected long-term rate of return on plan assets is based on a target allocation of investment types in such assets. At December 31, 2010, the target allocations for plan assets were 47.5% for equity securities, 40% for fixed-income securities and 12.5% for other investment types. Equity securities consist of investments in large capitalization and small capitalization companies, both domestic and international. Fixed-income securities include corporate bonds of investment-grade companies from diverse industries, United States Treasury obligations and asset-backed securities. Other investment types include short-term investment funds and a hedge fund of funds. We expect our long-term asset allocation on average to approximate the targeted allocation. We regularly review our actual asset allocation and periodically rebalance the investments to the targeted allocation when considered appropriate.
 
Pension expense increases as the expected rate of return on plan assets decreases. A decrease in our long-term rate of return assumption of 100 basis points would increase the expected 2011 pension expense by $6 million.
 
We discounted our future pension obligations using a weighted average rate of 5.50% and 6.00% at December 31, 2010 and 2009. The discount rate is determined at the end of each year based on the rate at which obligations could be effectively settled, considering the expected timing of future cash flows related to the plans. This rate is based on high-quality bond yields, after allowing for call and default risk. High quality corporate bond yield indices are considered when selecting the discount rate.
 
The pension liability and future pension expense both increase as the discount rate is reduced. Lowering the discount rate by 25 basis points would increase our pension liability at December 31, 2010, by $37 million, and increase estimated 2011 pension expense by $5 million.
 
At December 31, 2010, we had net actuarial losses of $357 million, which will be recognized as a component of pension expense in future years. These losses are primarily due to investment losses on plan assets in 2008, reductions in the discount rate since 2001 and increases in participant wages. We estimate that approximately $32 million and $26 million of the unrecognized actuarial losses will be included in pension expense in 2011 and 2012, respectively. The $32 million estimated to be recognized in 2011 is a component of the total estimated 2011 pension expense of $91 million referred to earlier in this section.
 
Future changes in plan asset returns, assumed discount rates and various other factors related to the participants in our defined benefit pension plans will impact future pension expense and liabilities. We cannot predict with certainty what these factors will be in the future.


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Contingencies and Legal Matters
 
For a detailed discussion of contingencies and legal matters, see Note 10 to the consolidated financial statements included in “Item 8. Financial Statements and Supplementary Data” of this report.
 
Critical Accounting Policies and Estimates
 
The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual amounts could differ from these estimates, and changes in these estimates are recorded when known.
 
The critical accounting policies used by management in the preparation of our consolidated financial statements are those that are important both to the presentation of our financial condition and results of operations and require significant judgments by management with regard to estimates used. Our critical accounting policies and significant judgments and estimates related to those policies are described below. We have reviewed these critical accounting policies with the Audit Committee of our Board of Directors.
 
Full Cost Method of Accounting and Proved Reserves
 
Policy Description
 
We follow the full cost method of accounting for our oil and gas properties. Under this method all costs associated with property acquisition, exploration and development activities are capitalized, including our internal costs that can be directly identified with such activities. Capitalized costs are depleted on an equivalent unit-of-production method, converting gas to oil at the ratio of six thousand cubic feet of gas to one barrel of oil. Depletion is calculated using the capitalized costs, including estimated asset retirement costs, plus the estimated future expenditures to be incurred in developing proved reserves, net of estimated salvage values. Costs associated with unproved properties are excluded from the depletion calculation until it is determined whether or not proved reserves can be assigned to such properties.
 
The full cost method subjects companies to quarterly calculations of a “ceiling,” or limitation on the amount of properties that can be capitalized on the balance sheet. The ceiling limitation is the discounted estimated after-tax future net revenues from proved oil and gas properties, excluding future cash outflows associated with settling asset retirement obligations included in the net book value of oil and gas properties, plus the cost of properties not subject to amortization. If our net book value of oil and gas properties, less related deferred income taxes, is in excess of the calculated ceiling, the excess must be written off as an expense. The ceiling limitation is imposed separately for each country in which we have oil and gas properties. An expense recorded in one period may not be reversed in a subsequent period even though higher oil and gas prices may have increased the ceiling applicable to the subsequent period.
 
Judgments and Assumptions
 
Our estimates of proved reserves are a major component of the depletion and full cost ceiling calculations. Additionally, our proved reserves represent the element of these calculations that require the most subjective judgments. Estimates of reserves are forecasts based on engineering data, projected future rates of production and the timing of future expenditures. The process of estimating oil, gas and NGL reserves requires substantial judgment, resulting in imprecise determinations, particularly for new discoveries. Different reserve engineers may make different estimates of reserve quantities based on the same data. Certain of our reserve estimates are prepared or audited by outside petroleum consultants, while other reserve estimates are prepared by our engineers. See Note 22 of the accompanying consolidated financial statements for a summary of the amount of our reserves that are prepared or audited by outside petroleum consultants.
 
The passage of time provides more qualitative information regarding estimates of reserves, when revisions are made to prior estimates to reflect updated information. In the past five years, annual performance revisions to our reserve estimates, which have been both increases and decreases in individual years, have averaged less


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than 2% of the previous year’s estimate. However, there can be no assurance that more significant revisions will not be necessary in the future. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions.
 
While the quantities of proved reserves require substantial judgment, the associated prices of oil, gas and NGL reserves, and the applicable discount rate, that are used to calculate the discounted present value of the reserves do not require judgment. The ceiling calculation